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	Site	Quarter	Title	Description
05000416/FIN-2018002-02	Grand Gulf	2018Q2	Failure to Follow ASME Requirements for Maintaining Inservice Inspection (ISI) Cycles and Perform ASME Required Inservice Inspections within the Scheduled ISI Cycle	The inspector identified 15 examples of a Green non-cited violation (NCV)of 10 CFR 50.55(a)(g)(4)(ii), which requires that inservice examination of components classified as American Society of Mechanical Engineers (ASME), Section XI, Code Class 1, Class 2, and Class 3 be conducted during successive 120-month inspection intervals, and requires compliance with the requirements of the latest edition and addenda of the ASME Code (and all its paragraphs) applicable to the specific interval, including maintaining the 120-month inspection interval in accordance with the ASME Code, Section XI, Paragraph IWA-2430. Specifically, the licensee inappropriately adjusted its second inservice inspection 120-month cycle, and failed to perform VT-3 and MT examinations of 15 class 1, class 2, and class 3 components, including the high pressure core spray pump attachment weld and reinforcing band before the third inservice inspection cycle expired on November 30, 2017, as required by 10CFR50.55(a)(g)(4)(ii).
05000416/FIN-2018001-05	Grand Gulf	2018Q1	Licensee-Identified Violation	10 CFR 50.72(b)(3)(v)(D) requires the licensee to report an event or condition that could have prevented fulfillment of a safety function (accident mitigation).Contrary to the above, from February 18, 2018, until February 23, 2018, Grand Gulf Nuclear Station failed to make a timely event report for an event or condition that could have prevented fulfillment of a safety function (accident mitigation). Specifically, Grand Gulf Nuclear Station experienced the concurrent inoperability of the division 2 diesel generator and the high pressure core spray diesel generator. Per Technical Specification Bases 3.8.1.E.1, there are insufficient standby ac sources available in this condition to power the minimum required engineered safety feature functions.Significance/Severity Level: In accordance with NRC Enforcement Policy, Section 6.9.d.9, the failure to make a report required by 10 CFR 50.72 is a Severity Level IV violation.Corrective Action Reference(s): The licensee entered the failure to make a timely report into the corrective action program as CR-GGN-2018-1595.
05000461/FIN-2017011-01	Clinton	2017Q4	Failure to Correct an Identified Degraded Condition on the Division 3 Shutdown Service Water Pump	A self-revealing finding and an apparent violation of 10 CFR 50, Appendix B, Criterion XVI, Corrective Action, with associated violations of Technical Specification (TS) 3.7.2 and TS 3.5.1 were identified on June 15, 2017, for the licensees failure to correct a degraded condition identified during the evaluation performed as a result of the Division 3 shutdown service water (SX) pump failure in 2014. Specifically, the licensee identified corrosion of the Division 3 SX pump sleeves as a contributing cause of the 2014 pump failure and failed to appropriately evaluate and correct this issue. This resulted in the Division 3 SX pumps failure to start on June 15, 2017, and rendered the Division 3 SX pump inoperable for a time longer than its TS allowed outage time. The licensee entered this issue into the corrective action program and implemented design changes to the pump and motor assembly, including installing a new motor with higher starting torque characteristics and replacing the pump shaft sleeves and packing with parts more resistant to corrosion. The licensee has completed multiple successful runs of the new pump with no abnormalities noted. The inspectors determined that the licensees failure to correct a degraded condition identified during the evaluation performed as a result of the 2014 Division 3 SX pump failure appears to be not in accordance with the requirements of 10 CFR 50, Appendix B, Criterion XVI, and was a performance deficiency. The performance deficiency was determined to be more than minor because it impacted the Mitigating Systems cornerstone attribute of equipment performance and adversely affected the cornerstone objective of ensuring the availability, capability and reliability of equipment that responds to initiating events. Specifically, the performance deficiency resulted in the failure of the Division 3 SX pump, which impacted the operability and functionality of the high pressure core spray system and the Division 3 emergency diesel generator. Using IMC 0609, Appendix A, Significance Determination Process for Findings At-Power, dated June 19, 2012, a Significance and Enforcement Review Panel preliminarily determined the finding to be of low to moderate safety significance. The inspectors determined that this finding affected the cross-cutting area of problem identification and resolution in the aspect of evaluation, where the organization thoroughly evaluates issues to ensure that resolutions address causes and extent of 3 conditions commensurate with their safety significance. Specifically, the licensee failed to properly evaluate the Division 3 SX pump sleeve corrosion rates when performing the component life evaluation, the component operability evaluation and the evaluation in response to the abnormal noises identified during periodic pump runs. (P.2)
05000440/FIN-2017008-01	Perry	2017Q4	Failure to Address the Susceptibility of the Condensate Storage TankLow Level Instrument Lines to Freeze	The team identified a finding of very-low safety significance (Green) and an associated NCV of Title 10 of the Code of Federal Regulations(CFR),Part 50, Appendix B, Criterion III, Design Control, and 10 CFR 50.63, Loss of All Alternating Current Power, for the licensees failure to evaluate the capability to transfer the high pressure core spray (HPCS)and the reactor core isolation cooling (RCIC) pumps suction source from the condensate storage tank (CST)to the suppression pool during cold weather conditions. Specifically, (1) monitoring of the CST level instrument lines heat tracing was inadequate to detect a credible common mode failure before the instrument lines would freeze and be rendered inoperable during normal operation, (2)the licensee did not address the condensate (CST) level instrument lines susceptibility to freeze during a cold weather loss of off-site power (LOOP) event with or without a design basis transient or accident, and (3)the licensee incorrectly evaluated the capability to transfer the HPCS pump suction source from the CST to the suppression pool during a cold weather station blackout (SBO) event. The licensee captured the issues within their Corrective Action Program (CAP) as Condition Report(CR) CR-2017-08685, CR-2017-08930, and CR-2017-09006. Corrective actions implemented included: increased the CST level instrument line heat tracing circuit monitoring frequency, revised the affected procedures ensured HPCS and RCIC are adequately aligned to the suppression pool during LOOP design basis events, and ensured a timely transfer of the HPCS and RCIC pump suctions to the suppression pool during a SBO. The performance deficiency was determined to be more-than-minor because it was associated with the Mitigating Systems cornerstone attribute of design control and affected the cornerstone objective of ensuring the availability,reliability, and capability of systems that respond to initiating events to prevent undesirable consequences.Specifically, the failure of the HPCS and or RCIC pumps to automatically transfer their suction source from the CST to the suppression pool upon reaching a low CST water level condition could damage the pump(s) thus preventing them to be used to mitigate a transient or accident. A detailed risk evaluation was performed and determined that the finding was of very-low safety-significance (Green). The team did not identify a cross-cutting aspect associated with this finding because it was not confirmed to reflect current performance due to the age of the performance deficiency. Specifically, the CST instrument lines were designed and the SBO coping strategy during cold weather was established more than 3 years ago.
05000397/FIN-2017003-01	Columbia	2017Q3	Inadequate High Pressure Core Spray Fill and Vent Procedure	The inspectors reviewed a self -revealed, non- cited violation of Technical Specification 5.4.1.a, for the licensees failure to have a high pressure core spray system fill and vent procedure appropriate to the circumstances. The licensee entered this issue into the corrective action program as Action Request 368872. The failure to have a high pressure core spray system fill and vent procedure appropriate to the circumstances was a performance deficiency. The performance deficiency was more than minor, and therefore a finding, because it affected the equipment performance at tribute of the Mitigating Systems Cornerstone and adversely affected the cornerstone objective to ensure the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences. Specifically, Procedure SOP- HPCS -FILL, HPCS Fill and Vent, Revision 11, was not appropriate to the circumstances in that it did not ensure the high pressure core spray instrumentation lines were clear of voids. As a result, air remained in the instrumentation lines , and the high pressure core spray minimum flow instrument, HPCS -FIS -6, was degraded. The inspector s performed the initial significance determination using Inspection Manual Chapter 0609, Appendix A, Exhibit 2, Mitigating Systems Screening Questions. The inspectors determined that the finding was of very low safety significance (Green) because: (1) the finding was not a deficiency affecting the design or qualification of a mitigating system; (2) the finding did not represent a loss of system and/or function; (3) the finding did not represent an actual loss of function of a single train for greater than its technical specification allowed outage time; and (4) the finding did not represent an actual loss of function of one or more non- technical specification trains of equipment designated as high safety -significant in accordance with the licensees maintenance rule program for greater than 24 hours. This finding had a cross -cutting aspect in the area of human performance, avoid complacency, in that the licensee failed to recognize and plan for the possibility of mistakes, latent issues, and inherent risk, even while expecting successful outcomes (H.12).
05000416/FIN-2017002-01	Grand Gulf	2017Q2	Failure to Establish an Appropriate Preventative Maintenance Procedure for the HPCS Jockey Pump	Green . The inspectors reviewed a self -revealed, non- cited violation of Technical Specification 5.4.1.a, for the licensees failure to establish appropriate procedural instructions for performing preventative maintenance on the high pressure core spray jockey pump. Specifically, on January 27, 2017, the high pressure core spray jockey pump failed because the licensee did not establish a preventative maintenance procedure that prescribes oil analysis and additional performance trending for the high pressure core spray jockey pump every 6 months consistent with the licensees preventative maintenance strategy template. On January 29, 2017, the licensee completed repairs and returned the high pressure core spray jockey pump and high pressure core spray system to operable status . The licensee has also incorporated oil analysis and performance trending into the preventative maintenance for jockey pumps. This issue has been entered into the licensees corrective action program as Condition Report CR -GGN -2017- 0917. The failure to establish appropriate preventative maintenance instructions for the high pressure core spray jockey pump was a performance deficiency. The performance deficiency was more than minor, and therefore a finding, because it was associated with the equipment performance attribute of the Mitigating Systems Cornerstone and adversely affected the cornerstone objective to ensure the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences. Specifically, the failure to establish appropriate preventative and predictive maintenance work instructions resulted in the unplanned inoperability and unavailability of the high pressure core spray system. Using Inspection Manual Chapter 0609, Appendix A, The Significance Determination Process (SDP) for Findings At -Power, dated June 19, 2012, and Inspection Manual Chapter 0609, Appendix A, Exhibit 2, Mitigating Systems Screening Questions, the inspectors determined that the finding resulted in a loss of system and/or function; therefore, a detailed risk evaluation was performed. A senior reactor analyst performed a detailed risk evaluation in accordance with Inspection Manual Chapter 0609, Appendix A, The Significance Determination Process (SDP) for Findings at Power. The NRC determined that the increase in core damage frequency for internal initiators was 1.59 E-7/year, and a bounding analysis of external initiators indicated that these events would not result in a 3 change in the color of the finding. Therefore, this finding is of very low safety significance (Green). The analyst also determined that an estimation of large early release frequency (LERF) was required. The result was an increase in LERF of 3.19E -8/year, which is of very low safety significance for LERF (Green). This finding had a cross -cutting aspect in the area of human performance associated with consistent process because the licensee did not use a consistent, systematic approach to make decisions. Specifically, the licensee did not use a consistent approach in developing a preventative maintenance strategy for the high pressure core spray jockey pump by utilizing the approved preventative maintenance strategy template (H.13).
05000397/FIN-2017002-04	Columbia	2017Q2	Licensee-Identified Violation	Title 10 CFR 50.55a(g)4, Inservice Inspection Standards Requirement For Operating Plants , requires , in part, that thro ughout the service life of a boiling water -cooled nuclear power facility, components that are classified as ASME Code Class 1, Class 2, and Class 3 must meet the requirements set forth in Section XI of the ASME Code. The ASME Code, Section XI, Article IWA -2610, requires that all welds and components subject to a surface or volumetric examination be included in the licensees inservice inspection program. This includes identifying each system support that is subject to Section XI requirements. Contrary to the above, prior to March 9, 2017, the licensee did not apply the applicable inservice inspection requirements to all system pressure boundaries within ASME Code Class 1, 2, and 3 boundaries. Specifically, the licensee failed to include the control rod d rive housing welds, as well as portions of the residual heat removal and high pressure core spray systems in their inservice inspection program. The licensee entered this issue into their corrective action program as AR 00343761 and reasonably determined the affected components and system remained operable. The licensee restored compliance by entering the components and systems into the ASME Section XI program. The finding was of very low safety significance (Green) because the finding did not represent an actual loss of safety function of a system or train, and did not result in the loss of a single train for greater than technical specification allowed outage time.
05000397/FIN-2017002-03	Columbia	2017Q2	Inadequate Corrective Actions Causes Failure of HPCS Room Normal Supply Fan	Green . The inspectors reviewed a self -revealed, non- cited violation of 10 CFR Part 50, Appendix B, Criterion XVI, Corrective Action, for failure to promptly identify and correct a condition adverse to quality. Specifically, since 2012, the licensee failed t o implement prompt corrective actions to correct an adverse condition related to the use of a contactor coil for a motor starter in the high pressure core spray room normal supply fan. As an immediate corrective action, the licensee replaced the contactor for the high pressure core spray room normal supply fan. The licensee entered this issue into the corrective action program as Action Request 360595. The failure to correct an adverse condition related to the use of a contactor coil for a motor starter in the HPCS room normal supply fan, though the licensee had an opportunity and plan to do so, was a performance deficiency. The performance deficiency was more than minor, and therefore a finding, because it affected the design control attribute of the Mitigating Systems Cornerstone and adversely affected the cornerstone objective to ensure the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences. Specifically, the licensees failure to correct the use of a contactor coil for a motor starter in the high pressure core spray room normal supply fan resulted in an inoperable fan, high pressure core spray bus 4160 VAC switchgear, and high pressure core spray pump during the January 25, 2017, event when smoke was observed from the motor control center. The inspectors performed the initial significance determination using NRC Inspection Manual Chapter 0609, Appendix A, Exhibit 2, Mitigating Systems Screening Questions. The inspectors determined that the finding was of very low safety significance (Green) because: (1) the finding was not a deficiency affecting the design or qualification of a mitigating system; (2) the finding did not represent a loss of system and/or function; (3) the finding did not represent an actual loss of function of a single train for greater than its technical specification allowed outage time; and (4) the finding does not represent an actual loss of function of one or more nontechnical specification trains of equipment designated as high safety -significant in accordance with the licensees maintenance rule program for greater than 24 hours. The inspectors determined that this finding did not have a cross -cutting aspect as the decision to not replace the contactor occ urred in 2014 and was not reflective of current performance.
05000461/FIN-2017002-03	Clinton	2017Q2	Unexpected Start of the Division 3 Emergency Diesel Generato	Green . The inspectors documented a self -revealed finding o f very low safety significance and an associated non- cited violation of Title 10 of the Code of Federal Regulations (CFR) Part 50, Appendix B, Criterion V, Instructions, Procedures, and Drawings, for the licensees failure to follow steps in Work Order (WO) 04640788 while performing troubleshooting on blown power transformer fuses in the division 3 emergency diesel start circuitry. Specifically, the electricians opened test switches in the wrong electrical cubicle resulting in the unexpected start of the division 3 emergency diesel generator and a loss of power to the 1C1 bus from an offsite source. The licensee entered this issue into their corrective action program (CAP) as Action Request (AR ) 04012393. As corrective actions, the licensee performed a human performance review to identify the reasons the procedure was not followed and restored power to the 1C1 safety bus . The performance deficiency was determined to be more than minor because it impacted the Initiating Event s cornerstone at tribute of human performance and adversely affected the cornerstone objective to limit the likelihood of events that upset plant stability and challenge critical safety functions during shutdown as well as power operations. Specifically, the failure of the electrical maintenance technicians to follow their procedures resulted in a loss of power to the 1C1 electrical bus. T he finding was screened against the Initiating Event s cornerstone and determined to be of very low safety significance because the loss of power to the 1C1 bus occurred while Clinton was in a refueling outage when the high pressure core spray system was removed from service and not being relied upon for shutdown safety defense in depth. The loss of the 1C1 bus did not affect decay heat removal from the core, did not affect reactor coolant inventory, and the event occurred while the refuel cavity was flooded up for refueling operations. The inspectors determined that this finding affected the cross -cutting area of human performance in the aspect of avoid complacency where individuals implement 3 appropriate error reduction tools. Specifically, as documented in the licensees human performance review, the electricians performing the work did not utilize any human performance tools to flag the equipment to be operated and improperly performed the concurrent verification of the component to be manipulated. (H.12)
05000458/FIN-2017001-02	River Bend	2017Q1	Failure to Properly Pre - Plan and Perform Maintenance on the Control Building Chilled Water System	Green . The inspectors identified a non- cited violation of Technical Specification 5.4, Procedures, for the licensees failure to properly pre-plan and perform maintenance on safety -related components in accordance with documented instructions appropriate to the circumstances. Specifically, the licensee used work order instructions that did not contain sufficient detail for the reassembly of SWP -PVY32C, a safety -related valve in the control building ventilation system . As a result, SWP -PVY32C developed a refrigerant leak, and on November 17, 2015 , the valve failed. This in turn caused the control building ventilation system to fail , and the high pressure core spray system was consequently declared inoperable. The licensee entered this condition into their corrective action program as Condition Report CR- RBS -2017- 02364. Corrective actions included incorporating the torque values into the model work order instructions for future maintenance and reassembly . The failure to properly pre-plan and perform maintenance on safety -related components in accordance with documented instructions was a performance deficiency. The performance deficiency was more than minor , and therefore a finding, because it was associated with the equipment performance attribute of the Mitigating Systems Cornerstone and adversely affected the cornerstone objective to ensure the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences. Specifically, when the control building ventilation system failed, it impact ed the operability of the high pressure core spray system. The inspectors screened the finding in accordance with NRC Inspection Manual Chapter 0609, Significance Determination Process. Using NRC Inspection Manual Chapter 0609, Appendix A, The Significance Determination Process (SDP) for Findings At -Power, Exhibit 2 Mitigating Systems Screening Questions, the inspectors determined that the finding was of very low safety significance (Green) because it did not affect the design or qualification of a mitigating structure, system, or component (and the structure, system, or component maintained its operability), it did not represent a loss of safety function, it did not represent an actual loss of function of at least a single train for greater than its technical specification outage time, and it did not represent an actual loss of function of one or more non-technical specification trains of equipment designated as high safety significant in accordance with the licensees Maintenance Rule program for greater than 24 hours. This finding has a cross- cutting aspect in the area of human performance, challenge the unknown, because individuals did not stop when faced with uncertain conditions. Specifically, workers proceeded with assembling the valve when the torque values or torqueing sequence were not specified (H.11)
05000298/FIN-2016008-01	Cooper	2016Q3	Possible Failure to Ensure that the Assumptions in the Engineering Analysis Remain Valid	As part of the transition to a performance-based, risk-informed fire protection program, the licensee adopted the requirements of NFPA 805. NFPA 805 requires the following in Section 2.6: Monitoring. A monitoring program shall be established to ensure that the availability and reliability of the fire protection systems and features are maintained and to assess the performance of the fire protection program in meeting the performance criteria. Monitoring shall ensure that the assumptions in the engineering analysis remain valid. The team reviewed selected samples of equipment monitored by the licensee using Procedure 3-CNS-DC-357, NFPA 805 Monitoring Program, Revision 0, to ensure that the licensees program properly implemented the requirements of NFPA 805, Section 2.6. The team also reviewed Engineering Report Number ER2015-002, NFPA 805 Fire Protection Monitoring Program, Revision 2. The team observed that for components used in the fire probabilistic risk assessment, the unavailability time for those components was monitored using the existing maintenance rule monitoring program. These components included the: Control rod drive pumps Core spray pumps Emergency diesel generators Emergency station service transformer Startup station service transformer High pressure core spray pump Instrument air compressors Residual heat removal pumps Standby liquid control pumps Service water pumps The team noted that the action levels for availability in the maintenance rule monitoring program were greater than the assumptions in the fire probabilistic risk assessment. With this observation, the team questioned the licensee as to whether this met the requirement in NFPA 805 to maintain the assumptions in the engineering analysis. The licensee informed the team that they had performed a sensitivity analysis to determine the significance of monitoring at a higher level of unavailability via the maintenance rule. This analysis determined an increase in core damage frequency for the additional unavailability time that could be accrued above the assumption for availability in the fire probabilistic risk assessment and up to the maintenance rule monitoring value for unavailability. This increase in core damage frequency was then determined to be acceptable if it did not exceed 1.0E-6/year. The team noted that for an individual component this screening criterion would not exceed more than 2 percent of the licensees baseline fire core damage frequency. The team was aware that some particular aspects of the monitoring program were being discussed between the industry and the NRCs Office of Nuclear Reactor Regulation during periodic public meetings which discussed Frequently Asked Question 10-0059, NFPA 805 Monitoring. The monitoring program and the sensitivity analysis approach used by the licensee are enveloped in these discussions. The team determined that additional information is required to determine if a performance deficiency exists. Specifically, the team needed to determine if the licensees action to set the action levels for the availability of some plant components at the components maintenance rule monitoring values and the performance of a riskinformed sensitivity analysis in an attempt to ensure that the assumptions in the engineering analysis remained valid would be an acceptable approach. Judgment on the suitability of this approach is pending further resolution of the monitoring program during discussions of Frequently Asked Question 10-0059, NFPA 805 Monitoring. The licensee entered this issue of concern into the corrective action program as Condition Report CR-CNS-2016-05109. This issue of concern is being treated as Unresolved Item 05000298/2016008-01, Possible Failure to Ensure that the Assumptions in the Engineering Analysis Remain Valid.
05000416/FIN-2015007-03	Grand Gulf	2015Q4	Lack of Coordination of Division III HPCS Switchgear 127N Undervoltage Relays	The following issues were discussed during the inspection; however, the team must review additional information provided by the licensee to determine whether these issues result in a more than minor performance deficiency or a violation of NRC requirements. In accordance with Inspection Manual Chapter 0612, this issue will be characterized as an unresolved item. The incoming offsite power supply circuit breakers for Division III 4160 V switchgear 17AC are equipped with 127N undervoltage relays. According to Drawing E-1009, One Line Meter and Relay Diagram, 4.16kV E.S.F. System Bus 17AC, Revision 9, these relays Trip incoming breaker to bus & start diesel. According to drawing E-0121-005, Summary of Relay Settings (ESF) 4.16 kV Bus 17AC and Diesel Gen 13, Revision 7, these relays are set with a 0 second time delay. This instantaneous time response potentially results in lack of coordination of the 127N undervoltage relays with high voltage system protective relays, switchgear overcurrent relays, and loss of voltage relays, thus preventing the other relays from performing their credited design functions. Protective devices that the 127N undervoltage relays are potentially not coordinated with are as follows: Protective relays associated the main transformer and its output circuit: Lack of coordination between the 127N undervoltage relays and the protective relays associated with the main transformer and its output circuit can result in coincident loss of two alternating current power supplies, contrary to the requirements of General Design Criterion 17. Grand Gulf Updated Final Safety Analysis Report Section 8.3.1.2.1 states: The degree of reliability of the power sources required for safe shutdown is considered very high due to independence and ample redundancy; it equals or exceeds all the requirements of Criterion 17. General Design Criterion 17 states: Provisions shall be included to minimize the probability of losing electric power from any of the remaining supplies as a result of, or coincident with, the loss of power generated by the nuclear power unit... Contrary to this General Design Criterion 17 requirement, a fault on the main transformer or its high voltage connection to the transmission system could cause coincident loss of electric power from both the main generator and the offsite power supply to Division III. The protective relaying on the main transformer and its output circuit is designed to initiate tripping of the main generator and isolation of the area of the fault without causing any cascading failures. However, the 127N undervoltage relay for the Division III 4160 V switchgear would also respond spuriously to the momentary voltage dip caused by the fault and cause loss of the offsite power supply to Division III. Transmission system bus protective relays: Grand Gulf Updated Final Safety Analysis Report Section 8.2, Offsite Power System, Subsection 8.2.2.1, Availability Considerations states: Short circuits on a section of a bus are isolated without interrupting service to any circuit other than that connected to the faulty bus section. Contrary to this requirement, the instantaneous setting of the 127N relays would not coordinate with the transmission bus protective relays and would react to the momentary voltage dip caused by a transmission system bus fault, resulting also in spurious loss of the offsite power supply to Division III. Loss of Voltage Relays: In addition to the 127N undervoltage relays, Division III high pressure core spray 4160 V switchgear 17AC is equipped with 127S1, S2, S3, and S4 loss of voltage relays and 127 1A, 1B, 2A, and 2B degraded voltage relays, which also trip the offsite power supply to 17AC upon actuation. NRC Regulatory Issue Summary 2011-12, Adequacy of Station Electric Distribution System Voltages, Revision 1, describes one of the functions of the degraded voltage relay time delay as follows: The time delay shall override the effect of expected short duration grid disturbances, preserving availability of the offsite power source(s). The same principle is relevant to the other undervoltage relays that automatically trip the switchgear offsite power supply. This conclusion is consistent with Grand Gulf Updated Final Safety Analysis Report Section 8.3.1.1.2.3, which states: Protective devices of Class 1E systems, particularly the ECCS, are set to maintain continuity of power as long as possible short of causing a derangement of the equipment. However, the 127N undervoltage relays do not preserve availability of power as long as possible in the event of harmless transmission grid voltage transients, such as those caused by lightning strikes and normally-cleared faults on transmission lines, because their instantaneous setting miscoordinates with the time delay setting of the Technical Specification credited loss of voltage relays 127S1, S2, S3, and S4. According to Technical Specification Table TR 3.3.8.1-1, the 127S1, S2, S3, and S4 loss of voltage relays have a time delay setting of 2.3 seconds. According to Section 6.17 of calculation JC-Q1P81-90027, Division III Loss of Bus Voltage Setpoint Validation (T/S 3.3.8.1), Revision 2, Spurious segregation from the offsite source is prevented by the time delay function. However, since the non- Technical Specification 127N relays react instantaneously to trip the offsite power source during momentary voltage dips, their 0-second time delay setting invalidates this credited design function of the 2.3-second time delay of the 127S1, S2, S3, and S4 loss of voltage relays. Therefore, spurious segregation from the offsite source is not prevented, and a vulnerability exists for unnecessary loss of offsite power events initiated by, and subsequent to, harmless voltage transients from the transmission system. An actual event of this type occurred on April 2, 2012, as described in Licensee Event Report 2012-003. A lightning strike on a 500 kV transmission circuit resulted in actuation of the instantaneous 127N relay and unnecessary loss of the offsite power supply to the Division III electrical distribution system. Switchgear 17AC offsite power supply circuit breaker overcurrent relays: Grand Gulf Updated Final Safety Analysis Report Section 8.3.1.1.4.2.5.3, HPCS Class 1E Electrical Equipment Circuit Protection states: Emphasis is given in preserving function and limiting loss of Class 1E equipment function in situations of power loss and equipment failure. Contrary to this statement, the instantaneous setting of the 127N undervoltage relays prevents the offsite power supply circuit breaker overcurrent relays from preserving function and limiting loss of Class 1E equipment function in the event of a switchgear bus fault. Switchgear 17AC offsite power supply circuit breakers are equipped with 151B overcurrent relays that, when actuated, trip and lockout the switchgear supply breakers. The purpose of the lockout function is to prevent attempted reenergization of a faulted bus. However, due to the instantaneous response time of the 127N undervoltage relays, the fault would be cleared and the bus deenergized on the undervoltage signal before the overcurrent relays could respond and initiate the bus lockout signal. This would result in automatic starting of the Division III diesel generator, closure of the diesel generator output breaker onto the faulted bus, and the potential for damage to the diesel generator and further damage to the switchgear. Switchgear 17AC feeder circuit breaker overcurrent relays: The circuit breakers for feeders downstream of switchgear 17AC are equipped with 150/151M and 150/151T overcurrent relays that are designed to isolate downstream faults locally. Grand Gulf Updated Final Safety Analysis Report Section 8.3.1.1.2.3, Control Power and Circuit Protection states: A complete analysis of the application and coordination of the protective devices on Class 1E distribution has been conducted. This analysis shows that under design operation of these devices, faults, and undervoltages will be detected and corrected at the lowest level of distribution. Referring to the 150/151M and 150/151T overcurrent relays, Grand Gulf Updated Final Safety Analysis Report Section 8.3.1.1.4.2.5.3 states: Relay settings are coordinated in such a way that interference of service is not communicated to a higher level involving equipment other than that immediately affected by the fault or overload. Contrary to these requirements, the licensee failed to perform a coordination analysis or to ensure that interference of electrical service is limited as described. The voltage dip caused by a fault on a 4160 V circuit downstream of switchgear 17AC would be detected by the 127N relay, which would react instantaneously to trip the 17AC switchgear offsite power supply circuit breaker rather than isolating the fault locally at the downstream circuit breaker. This is contrary to the design criterion that the fault be detected and corrected at the lowest level of distribution and maintain continuity of power to the switchgear. These issues were entered into the licensees corrective action program as Condition Report CR-GGN-2015-4973.
05000416/FIN-2015004-04	Grand Gulf	2015Q4	Failure to Establish Adequate Maintenance Instructions to Perform Work Activities on the Division III Diesel Generator Overspeed Trip Limit Switch	The inspectors reviewed a self-revealing non-cited violation of Technical Specification 5.4.1.a, for the failure to establish adequate maintenance instructions to perform work activities on the division III diesel generator overspeed trip limit switch. Specifically, work orders did not contain adequate instructions to check the overspeed trip switches alignment in accordance with vendor recommendations. As a result, the division III diesel generator was rendered inoperable and unavailable. On July 15, 2015, the licensee appropriately set the limit switch to overspeed actuating arm engagement, and returned the diesel generator to operable. The licensee entered this issue into their corrective action program as Condition Report CR-GGN-2015-3985. The failure to establish adequate work instructions to verify the overspeed switch was properly set and adjusted was a performance deficiency. This performance deficiency is more than minor, and therefore a finding, because it is associated with the equipment performance attribute of the Mitigating Systems Cornerstone and adversely affected the cornerstone objective to ensure the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences. Specifically, work orders to check the overspeed trip switches alignment did not contain adequate instructions to successfully perform the maintenance. The division III diesel generator was declared inoperable when the diesel spuriously tripped during the monthly surveillance run on July 13, 2015. The inspectors performed the initial significance determination for the division III emergency diesel generator failure. The inspectors used the NRC Inspection Manual 0609, Appendix A, Exhibit 2, Mitigating Systems Screening Questions. The finding required a detailed risk evaluation because it involved a performance deficiency that represented a loss of the high pressure core spray system following a postulated loss of offsite power because of the failure of the division III diesel generator. The Region IV senior reactor analyst performed a detailed risk evaluation in accordance with NRC Inspection Manual 0609, Appendix A, Section 6.0, Detailed Risk Evaluation. The detailed risk evaluation result is a finding of very low safety significance (Green). The calculated change in core damage frequency of 5.0 x 10-7 was dominated by an unrecovered station blackout beyond battery depletion. The analyst determined that the bounding risk of a large, early release of radiation was 9.6 x 10 . For the details of the analysis, see Attachment 3. Work orders were developed to address operating experience provided from the diesel generator vendor to the industry in December 2011. The inspectors determined that the cause of the deficiency occurred in 2011, and therefore, determined the finding did not have a cross-cutting aspect since it is not indicative of current licensee performance.
05000458/FIN-2015009-04	River Bend	2015Q2	Failure to Identify High Reactor Water Level as a Condition Adverse to Quality	The team identified a non-cited violation of 10 CFR Part 50, Appendix B, Criterion XVI, Corrective Action, for the licensees failure to assure a condition adverse to quality was promptly identified. Specifically, the licensee failed to identify, that reaching the reactor pressure vessel water Level 8 (high) setpoint, on December 25, 2014, was an adverse condition, and as a result, failed to enter it into the corrective action program. To restore compliance, the licensee entered this issue into their corrective action program as Condition Report CR-RBS-2015-00620 and commenced a causal analysis for Level 8 (high) trips. This performance deficiency is more than minor, and therefore a finding, because it is associated with the equipment performance attribute of the Mitigating Systems Cornerstone and adversely affected the cornerstone objective to ensure the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences. Specifically, failure to identify Level 8 (high) conditions and unplanned automatic actuations as conditions adverse to quality, would continue to result in the undesired isolation of mitigating equipment including reactor feedwater pumps, the high pressure core spray pump, and the reactor core isolation cooling pump. The team performed an initial screening of the finding in accordance with Inspection Manual Chapter 0609, Appendix A, The Significance Determination Process (SDP) for Findings At-Power. Using Inspection Manual Chapter 0609, Appendix A, Exhibit 2, Mitigating Systems Screening Questions, the team determined that the finding is of very low safety significance (Green) because it: (1) was not a deficiency affecting the design or qualification of a mitigating structure, system, or component, and did not result in a loss of operability or functionality; (2) did not represent a loss of system and/or function; (3) did not represent an actual loss of function of at least a single train for longer than its technical specification allowed outage time, or two separate safety systems out-of-service for longer than their technical specification allowed outage time; and (4) did not represent an actual loss of function of one or more non-technical specification trains of equipment designated as high safety-significant in accordance with the licensees maintenance rule program. This finding has an avoid complacency cross-cutting aspect within the human performance area because the licensee failed to recognize and plan for the possibility of mistakes, latent issues, and inherent risk, even while expecting successful outcomes. Specifically, the licensee tolerated leakage past the feedwater regulating valves, did not plan for further degradation, and the condition ultimately resulted in the Level 8 (high) trip of the running reactor feedwater pump on December 25, 2014 (H.12).
05000461/FIN-2015002-02	Clinton	2015Q2	Post-Maintenance Test Failed To Demonstrate Required Flow Through RCIC Room Cooler	A self-revealed finding of very low safety significance and an associated NCV of 10 CFR 50 Appendix B, Criterion XI, Test Control, was documented by the inspectors for the failure to perform adequate post-maintenance (PM) testing that would assure that the RCIC room cooler would perform its intended function when restored to service following maintenance. Specifically, the licensee declared the room cooler operable with insufficient cooling flow through the cooler. The licensee documented the issue in the CAP as AR 02447013. The licensee operated the RCIC room cooler outlet valve from its throttled position to fully open to flush the seat and the upstream piping and positioned the valve to maintain the required flow to restore the cooler to an operable condition. The failure to perform adequate PM testing that would assure that the RCIC room cooler would perform its intended function when restored to service following maintenance was a performance deficiency. The performance deficiency was determined to be more than minor in accordance with IMC 0612, Power Reactor Inspection Reports, Appendix B, Issue Screening, dated September 7, 2012, because it was associated with the procedure quality attribute of the Mitigating Systems cornerstone and adversely affected the cornerstone objective to ensure the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences and is, therefore, a finding. Using IMC 0609, Attachment 4, Initial Characterization of Findings, and Appendix A, The Significance Determination Process for Findings at Power, dated June 19, 2012, the finding was screened against the Mitigating Systems cornerstone and determined to need a detailed risk evaluation because the finding represents the loss of a system and/or function. The Region III Senior Reactor Analysts (SRAs) evaluated the finding using the Clinton Station Standardized Plant Analysis Risk (SPAR) Model Version 8.17, Systems Analysis Programs for Hands-on Integrated Reliability Evaluations (SAPHIRE) Version 8.1.2. The SRAs reviewed the licensees Apparent Cause Investigation Report (IR) 2447013. The exposure time was assumed to be 150.5 hours based on information in that report. The SRAs modeled the condition using failure of the RCIC pump as a surrogate for failure of the RCIC room cooler. The basic event representing the RCIC pump failure-to-run was set to True for the 150.5 hour duration. The result was a change in core damage frequency of 9.98E-08/yr. The dominant sequence was a station blackout initiating event; failure of high pressure core spray; failure of RCIC; and failure to recover offsite or emergency alternating current (AC) power within 30-minutes. Based on the detailed risk evaluation, the finding is best characterized as a finding of very low safety-significance (Green). The inspectors determined this finding affected the cross-cutting area of human performance in the aspect of work management where the organization implements a process of planning, controlling, and executing work activities such that nuclear safety is the overriding priority. The work process includes the identification and management of risk commensurate to the work and the need for coordination with different groups of job activities. Specifically, the licensee failed to plan and execute adequate PM testing that would have ensured the satisfactory operation of the RCIC room cooler following planned maintenance. (H.5)
05000458/FIN-2015001-01	River Bend	2015Q1	Failure to Perform Adequate Operability Evaluations on Degraded High Pressure Core Spray System	The inspectors identified a non-cited violation of 10 CFR Part 50, Appendix B, Criterion V, Instructions, Procedures, and Drawings, for the licensees failure to perform an adequate operability evaluation in accordance with Entergy Procedure EN-OP-104, Operability Determination and Functionality Assessment. Specifically, operations staff failed to properly evaluate leakage from the suppression pool through the high pressure core spray system. The licensee entered this issue into their corrective action program as Condition Report CR-RBS-2014-04004. The failure to perform an adequate operability determination for leakage from the safety-related suppression pool was a performance deficiency. This performance deficiency is more than minor, and therefore a finding, because it adversely affected the configuration control attribute of the Mitigating Systems Cornerstone objective to ensure the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences. Specifically, a subsequent operability determination classified the suppression pool as inoperable. The inspectors used NRC Inspection Manual Chapter 0609, Appendix A, The Significance Determination Process (SDP) for Findings At-Power, dated June 19, 2012, to evaluate the issue. The finding required a detailed risk evaluation because it involved the potential loss of system and/or function. A Region IV senior reactor analyst performed a detailed risk evaluation for the issue. In the detailed risk evaluation, the senior reactor analyst concluded that the finding was determined to have very low safety significance (Green) because the high pressure core spray system would have remained functional for 21 days which is in excess of the probabilistic risk assessment mission time of 24 hours. The finding also did not screen as risk significant for large early release frequency. The finding has a cross-cutting aspect in the area of human performance associated with Challenge the Unknown: Individuals stop when faced with uncertain conditions. Risks are evaluated and managed before proceeding. Specifically, station operators, and the condition review group, failed to evaluate the condition of the suppression pool when the source of the leakage was uncertain (H.11).
05000461/FIN-2014003-02	Clinton	2014Q2	Failure to Develop Adequate Procedures for Pre-Planning and Performing Maintenance Affecting Safety-Related Hydramotor	The inspectors documented a self-revealing non-cited violation of Clinton Power Station Technical Specification 5.4.1, Procedures for a failure to develop adequate procedures for properly pre-planning and performing maintenance affecting the performance of safety-related equipment which resulted in the subsequent failure of the Division 3 Diesel Room Ventilation damper hydramotor on August 15, 2013. Specifically, during pre-scheduled performance testing of the Division 3 (High Pressure Core Spray System) Emergency Diesel Generator Room Ventilation Damper hydramotor, the ventilation supply air intake damper, 1VD01YC, failed to open as a result of Damper Hydramotor 1TZVD003A experiencing an age-related degradation failure. This was due in part to the licensees failure to properly pre-plan and perform the appropriate preventive maintenance for the hydramotor due to inadequate procedures. Procedure WC-AA-113, Predefine Database Revisions, Revision 2, did not provide adequate instructions appropriate to the circumstances to properly pre-plan and perform maintenance affecting the performance of safety-related equipment. This resulted in a loss of safety function of the Division 3 Diesel Generator and its supported High Pressure Core Spray system because of the low confidence that diesel room temperature would be maintained to support the diesel during an event when it would be required to perform its function. The licensee replaced the failed hydramotor, performed testing on the new hydramotor, restored the diesel ventilation system to an operable status, and changed WC-AA-113 to ensure that work would be properly scheduled in the future. This issue is documented the corrective action program as IR 1546973 and IR 1547294. The performance deficiency was more than minor because it was associated with the equipment performance attribute of the mitigating systems cornerstone attribute and adversely affected the cornerstone objective to ensure the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences and is therefore a finding. Using IMC 0609, Appendix A, The SDP for Findings At-Power, issued June 19, 2012, Exhibit 2 for the Mitigating Systems Cornerstone. The inspectors answered Yes to the screening question under the Mitigating Screening Cornerstone Does the finding represent a loss of system and/or function? since the finding resulted in a loss of safety function. Therefore, a detailed risk evaluation was performed using IMC 0609, Appendix A. The SRAs evaluated the finding using the Clinton SPAR model version 8.17, SAPHIRE version 8.1.0 and concluded that the risk increase to the plant due to this finding is very low (Green). The inspectors determined that no cross-cutting aspect will be assigned to this performance deficiency since it occurred in 2005 and is not indicative of current plant performance. (Section 4OA3)
05000263/FIN-2014003-04	Monticello	2014Q2	Licensee-Identified Violation	Title 10 CFR 50, Appendix B, Criterion III, Design Control, requires measures be established for the selection and review for suitability of application of material, parts, equipment, and processes that are essential to the safety-related functions of the SSCs. Contrary to this requirement, the licensee identified that from 2009 until November 20, 2013, NSR parts were installed in safety-related components. During operating experience review, the licensee identified the potential for NSR parts, such as gaskets and packing to be installed in safety-related systems. The licensee conducted an evaluation from 2009 forward to determine the use of both soft and hard NSR parts in limited volume safety-related systems or other applications where it performs a safety-related function. Eight occurrences of soft NSR parts installed in limited volume safety-related systems (SBLC, diesel fuel oil, alternate nitrogen, and HPCI) were identified. Four occurrences of hard NSR parts installed in limited volume safety-related systems (alternate nitrogen, high pressure core spray, and RCIC) were identified. Lastly, seven occurrences were identified by the licensee where hard NSR parts (key, fuses, relay, seal kit, and sealant) were installed in other applications where it performs a safety-related function. The licensee entered this issue into its corrective action program, CAPs 1407369 and 1410037, and through evaluation has determined the safety-related components impacted by the use of NSR parts are operable but non-conforming. The licensee has established actions to replace the identified NSR parts. The inspectors determined that this issue was more than minor because, if left uncorrected, the installation of parts/materials which fail to meet requirements could lead to subsequent part failure and adverse impact the ability of safety-related equipment to perform its safety function. Specifically, the licensee failed to establish measures for the selection of parts that are essential to the safety-related functions of SSCs. As a result, the licensee installed NSR parts in safety-related systems. The inspectors determined that this issue was associated with the Mitigating Systems cornerstone and could be evaluated using the SDP. The inspectors used IMC 0609, Attachment 0609.04, Appendix A, Exhibit 2, Mitigating Systems Screening Questions, dated June 19, 2012, and concluded that this issue was of very low safety significance (Green) because the finding was associated with a deficiency that only affected the design or qualification of the specific SSCs.
05000397/FIN-2014003-08	Columbia	2014Q2	Licensee-Identified Violation	Columbia Generating Station Operating License, Condition 2.C(14), requires, in part, that the licensee shall implement and maintain in effect all provisions of the approved fire protection program as described in section 9.5.1 and Appendix F of the FSAR for the facility. Columbia Generating Station FSAR, Appendix F, Fire Protection Evaluation, section F.4.4.4, Detailed Fire Hazard Analysis by Area, states, in part, for the main control room (Fire Area RC-10), a design basis fire will be confined to the fire area and systems needed for post-fire safe shutdown will remain free of fire damage. Contrary to the above, prior to February 24, 2014, the licensee failed to implement and maintain in effect all provisions of the approved fire protection program as described in Appendix F of the FSAR. Specifically, because of unfused DC ammeters in the main control room, the licensee failed to ensure that for a design basis fire, the fire will be confined to Fire Area RC-10 and that the systems needed for post-fire safe shutdown will remain free of fire damage. This finding was identified by the licensee and entered in the licensees corrective action program as AR 303326 and AR 304147. A senior reactor analyst performed a detailed risk evaluation and determined that the associated change to the core damage frequency was approximately 3.8E-7. The change to the large early release frequency was approximately 5E-8/year. Therefore, the finding was of very low safety significance (Green). The dominant core damage sequences involved a control room fire initiating event in Panel P-800, loss of Division I and Division II emergency AC power sources, and failure of the high pressure core spray system (failure of either the diesel or pump). The Division II emergency diesel generator failed because of secondary fires. The ability to recover the Division I emergency diesel generator at the remote shutdown panel helped to minimize the risk.
05000461/FIN-2014007-01	Clinton	2014Q1	Interpretation of Requirements for Multiple Spurious Operations	Based on discussions with the licensee, the inspectors identified several differences in interpretation of requirements between the inspectors and the licensee with respect to the requirements for addressing multiple spurious operations (MSOs). Requirement for Addressing Multiple Spurious Operations: The licensee expressed the belief that addressing MSOs was a voluntary effort on their part versus a requirement. Although the licensee had expended resources to address MSOs, the licensee had not updated their licensing basis documents, such as their SSD analysis, to reflect the procedure changes and modifications implemented to meet the intent of Nuclear Energy Institute (NEI) 00-01, Guidance for Post-Fire Safe Shutdown Circuit Analysis, Revision 2. Applicability of Appendix R to MSOs: The licensee presented the view that the references to hot shorts (plural) in 10 CFR Part 50, Appendix R, Sections III.G and III.L, were only in sections of Appendix R, which pertained to the SSD train, i.e., the train to be free of fire damage. The inspectors noted that the sections with the references to hot shorts (plural) also included associated non-safety circuits that could prevent operation or cause mal-operation of systems necessary to achieve and maintain hot shutdown. As such, the inspectors considered MSOs as required to be addressed. Licensing Basis Applicability for MSOs: The inspectors noted that although Clinton Power Station is a post-1979 plant, the licensee committed to meeting Appendix R or providing equivalent protection as discussed in Section 9.5.8 of NUREG-0853, Supplement 1. In addition, Section 9.5.1 of the Updated Safety Analysis Report (USAR) noted that the licensee committed to meet Section III.G of 10 CFR Part 50, Appendix R with exceptions identified in their SSD analysis. Except for two sets of redundant valves in series, the licensee did not take any exceptions to Appendix R with respect to MSOs. The licensee presented the view that no general exceptions to MSOs were taken at the time of licensing because the common understanding was MSOs were not a consideration except as identified in Generic Letter 81-12, Fire Protection Rule for high-low pressure interfaces. Number of MSOs to be evaluated: The licensee performed evaluation Engineering Change (EC) 383786, MSO Scenario 5a Additional Components Load onto Credited EDG, revision 1, to address emergency diesel generator (EDG) loading. Although the licensee evaluated 4 kiloVolt loads, the licensee chose not to evaluate 480 Volt (V) loads. The licensee cited NEI 00-01, Section 4.4.3.4, as a basis for excluding 480V loads from their review. In discussions with the licensee, the inspectors identified two interpretation issues as discussed below. The inspectors requested the licensee to perform a qualitative analysis to gauge the significance of excluding the 480V loads. In response, the licensee reviewed 480V loads greater than 30 horsepower (HP) which had not already been accounted for in the load profile. Seven such additional loads were identified which totaled 300 HP. The potential 300 HP in additional loads was within the margin for the peak ratings of the EDGs. The licensee also noted that the load profile used reflected loss-of-offsite power (LOOP) combined with loss-of-coolant accident (LOCA) loads which was a more demanding load profile than LOOP only loads which would be expected in the event of a fire. With respect to the NEI 00-01 guidance, the interpretation issues were: Extent of Endorsement of NEI 00-01 Chapter 4: Regulatory Guide 1.189, Fire Protection for Nuclear Power Plants, Revision 2, states that The approach outlined in Chapter 4 of NEI 00-01, which relies on the Expert Panel Process and the Generic List of Multiple Spurious Operations contained in Appendix G to that document, provides an acceptable methodology for the identification of multiple spurious actuations that may affect safe-shutdown success path SSCs. The inspectors view was that the endorsement was limited to use of the expert panel process and the list of MSOs in Appendix G of NEI 00-01 for guidance. The licensees view was that the entire chapter had been endorsed by the NRC as the NRC had not taken any exceptions. Limiting Analysis of Multiple Spurious Operations to Four Components: In both Section 3.5.1.2 and Section 4.4.3.4, NEI 00-01 states: ... if the combined MSOs involve more than a total of four components or if the MSO scenario requires consideration of sequentially selected cable faults of a prescribed type, at a prescribed time, in a prescribed sequence in order for the postulated MSO combination to occur, then this is considered to be beyond the required design basis for MSOs. The inspectors considered the statements made with respect to limiting consideration of MSOs to four components to be in the context of considering MSOs from a combination of multiple MSO scenarios. The inspectors view was that the limitation of the number of MSOs to four components was not applicable within a single scenario. The licensees point of view was that it was acceptable to limit the review of MSOs to a maximum of four components within a single MSO scenario as well as combinations of MSO scenarios. The inspectors were concerned because the limitation of four components was an arbitrary number of components with no technical basis to support the number four. Excluding review of more than four components could result in failing to address adverse component actuation scenarios which could compromise the SSD of a plant during a fire. Determination of SSD Path Components: High pressure core spray (HPCS) was credited for inventory control in the event of a fire in the west portion of containment. Section III.L of Appendix R to 10 CFR Part 50 and Section 5.1 of Regulatory Guide 1.189, Revision 2, identified the reactor coolant make-up function (i.e., inventory control) as one of the functions necessary to meet post-fire safe-shutdown performance goals. Section 3.1 of NEI 00-01, Revision 2, also identified inventory control as a function required for post-fire safe shutdown. As such, the HPCS system was a system required for hot shutdown (sometimes referred to as a Green Box system) versus a system characterized as important to safety (i.e., an Orange Box system). However, Section 3.2.2 of USAR, Appendix F, identified that cable damage due to a fire in the west portion of containment could cause spurious actuation of HPCS due to impacts upon the HPCS initiation logic. In the event of inadvertent HPCS operation, operators would be directed by procedure to place the HPCS pump control switch in the stop position to prevent reactor vessel overfill. Placing the HPCS pump control switch in the stop position would prevent automatic initiation of the HPCS system in addition to preventing spurious operation. Manual operation of HPCS from the control room would be required to maintain inventory control. The use of manual actions would normally be considered acceptable for a system characterized as important to safe shutdown (i.e., Orange Box) but not acceptable for a system required for hot shutdown (i.e., Green Box). The inspectors considered crediting the placement of the pump control switch in the off position to be operating outside the normal functioning of the system and to not represent a train free of fire damage. Although the inspectors acknowledged that the automatic feature of HPCS may not explicitly be needed to provide inventory control, the inspectors questioned why the automatic feature was not characterized as a required for hot shutdown component (i.e., a Green Box component) and protected accordingly. The licensees position was that only manual operation of the pump was credited for safe shutdown and automatic operation of the pump was unnecessary. The licenseenoted that Section 3.3.1.1.4.1 of NEI 00-01 stated The automatic ignition logics for the credited post-fire safe shutdown systems are generally not required to support safe shutdown. Typically, each system can be controlled manually by operator actuation in the main control room or emergency control station. While this statement is true, in general, and certainly applicable for important to safe shutdown functions, it does not address the adequate protection for functions of a required for safe shutdown system that do not manually operate the system, but do adversely affect its safe shutdown function. These interpretation issues are considered an unresolved item (URI) pending furtherconsideration of the above interpretations. (URI 05000461/2014007-01, Interpretation of Requirements for Multiple Spurious Operations).
05000461/FIN-2013005-05	Clinton	2013Q4	Failure to Assess and Manage Risk Associated with the Performance of Surveillance Testing on Average Power Range Monitors	Inspectors reviewed a self-revealing NCV of 10 CFR 50.65(a)(4) for failing to manage risk when the Division 4 Nuclear System Protection System (NSPS) inverter unexpectedly transferred from its normal direct current (DC) power source to its alternate alternating current (AC) power source during the Average Power Range Monitor (APRM) D surveillance test. Specifically, the installed operational barrier failed to protect a fus block when a test cable connector was inadvertently dropped. This caused a momentary electrical short and resulted in the inverter to transfer power sources. The licensee documented this issue in the CAP as IR 01476647 and performed (1) a standdown with instrument maintenance craftsmen to discuss the event and lessons learned, (2) changes to the licensees risk/hazards assessment process to include a checklist designed to aid in challenging jobsite conditions, (3) conduct of paired observations by maintenance department managers on use of the checklist, and (4) a case study with the maintenance shops using this event to highlight determining risk perception and robust protective barriers. The inspectors determined that the licensees failure to adequately manage the risk associated with performance of surveillance testing for APRM D was a performance deficiency. The performance deficiency is more than minor because it was associated with the configuration control attribute of the MS cornerstone and adversely affected the cornerstone objective to ensure the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences. The performance deficiency involved the licensees assessment and management of risk associated with performing maintenance in accordance with 10 CFR 50.65(a)(4); therefore the inspectors used IMC 0609, Attachment 4 Initial Characterization of Findings, and Appendix K, Maintenance Risk Assessment and Risk Management Significance Determination Process, and determined that a detailed risk evaluation would be required since the issue represented an actual loss of safety function of a system. The Region III Senior Reactor Analyst (SRA) completed a detailed risk evaluation using the NRCs Standardized Plant Analysis Risk (SPAR) model for Clinton Power Station (CPS), Version 8.17 and SAPHIRE Version 8.09 to calculate an Incremental Core Damage Probability Deficit (ICDPD) for the unevaluated condition. The SRA ran the SPAR model conservatively assuming that High Pressure Core Spray System (HPCS) was unavailable during the 6-hour time. The result was an ICDPD of less than 2E-08/year. In accordance with IMC 0609, Appendix K, because the ICDPD was not greater than 1E-06/year, the finding was determined to be of very low safety significance (i.e. Green). The finding was determined to have a cross-cutting aspect in the area of huma performance, associated with the work practices component, in that personnel wor practices are used commensurate with the risk of the assigned task, such that wor activities are performed safely. Specifically, the technicians did not perform adequat self or peer checks after installation of the barrier to ensure the barrier would provid protection from shorting.
05000373/FIN-2013004-02	LaSalle	2013Q3	Inadequate Procedures Led to Pin Hole Leaks in High Pressure Core Spray Piping	A self-revealed finding of very low safety significance and associated non-cited violation of Title 10 CFR Part 50, Appendix B, Criterion V, Instructions, Procedures, and Drawings, was identified for the failure to have procedures adequate for the circumstances during long-term operation of the high pressure core spray (HPCS) system on minimum flow. Specifically, three small holes developed in the Unit 2 HPCS minimum flow line elbow due to cavitation and other flow-related wear caused by inconsistent procedural guidance regarding operation in the minimum-flow mode. The licensee promptly repaired the system leak and entered the issue into its CAP as ARs 1503825 and 1530682, which included the performance of an apparent cause evaluation. Further corrective actions included the revision of the affected procedures. The finding was determined to be more than minor because it was associated with the Mitigating Systems and Barrier Integrity cornerstone attributes of Procedure Quality and adversely affected the cornerstone objectives of ensuring the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences and providing reasonable assurance that physical design barriers protect the public from radionuclide releases caused by accidents or events. Specifically, the procedural guidance given to operate the HPCS system was inadequate to prevent long-term operation of the system in the minimum flow mode of operation, which led to cavitation and flow-induced wear, causing the failure of the Unit 2 HPCS minimum flow line and inoperability of the HPCS system as well as the primary containment boundary. The inspectors determined that the finding could be evaluated in accordance with IMC 0609, Appendix A, The Significance Determination for Findings At-Power, and Appendix H, Containment Integrity Significance Determination Process. Further, it was determined that a phase two risk assessment was necessary because the finding impacted suppression pool integrity, and through that process, this issue screened as Green. The inspectors did not identify a cross-cutting aspect associated with this finding.
05000220/FIN-2013007-01	Nine Mile Point	2013Q3	Failure to Identify and Correct a Condition Adverse to Quality Associated With HPCS Medium Voltage Power Supply Cables	The inspectors identified an NCV of 10 CFR 50, Appendix B Criterion XVI, Corrective Actions, because between November 5, 2012, and July 22, 2013, NMPNS did not promptly identify and correct a failed automatic de-watering system for the buried high pressure core spray (HPCS) medium voltage power supply cable duct bank. As a result, on July 22, 2013, NMPNS unexpectedly discovered significant water level in the two manholes that contained the buried HPCS cable duct bank. NMPNS subsequently determined that multiple level switches for the de-watering system had failed. In response, NMPNS pumped down the affected manholes, replaced the failed level switches and initiated weekly manual pump downs of the manholes until final corrective actions could be completed. NMPNS entered this performance deficiency into the NMPNS CAP under CR-2013-006992. The inspectors determined that this performance deficiency was more than minor because if left uncorrected the failed automatic dewatering system would have become a more significant safety concern. Specifically, with no preventative maintenance (PM) task to inspect and test the dewatering system and no work order (WO) scheduled to investigate the cause of the MH-1 hi-hi level alarm, the inspectors determined that, based on NMPNS previous experience of rising level in this manhole and wetting of these cables, it was not likely that NMPNS would identify the failed de-watering system before the HPCS power supply cables were wetted. Wetted cables become a more significant concern because, in accordance with industry and NRC operating experience, the long term reliability of medium voltage cables is negatively affected when wetted. In accordance with IMC 0609.04, Initial Characterization of Findings, and Exhibit 2 of IMC 0609, Appendix A, The Significance Determination Process for Findings At-Power, issued June 19, 2012, the inspectors determined that the finding was of very low safety significance (Green), because the finding was not a design or qualification deficiency, did not represent a loss of safety system function, and did not screen as potentially risk significant due to external initiating events. The inspectors determined that this finding had a cross-cutting aspect in the area of human performance, resources, because NMPNS did not maintain long term plant safety by maintenance of design margins, minimization of long-standing equipment issues, minimizing PM deferrals, and ensuring maintenance and engineering backlogs which are low enough to support safety. Specifically, an NMPNS planner changed the scope of a PM task to eliminate inspecting MH-1 and MH-3 cable ducts every six months, and as a result, PM activities were not performed in November 2012 and May 2013. This error prevented NMPNS from identifying the condition adverse to quality associated with the HPCS medium voltage power supply cable duct bank de-watering equipment.
05000397/FIN-2013004-02	Columbia	2013Q3	Licensee-Identified Violation	Technical Specification 5.4.1.a requires, in part, that written procedures be established, implemented, and maintained as recommended in Regulatory Guide 1.33, Revision 2, Appendix A, dated February 1978. Paragraph 9.a of Regulatory Guide 1.33, Appendix A, requires that maintenance that can affect the performance of safety-related equipment should be properly preplanned and performed in accordance with written procedures, documented instructions, or drawings appropriate to the circumstances. Contrary to the above, on February 19, 2013, maintenance was performed on the motor control center for high pressure core spray pump HPCS-P-2 under Work Order 02025234, but was not completed in accordance with written instructions. Specifically, Step 4.2 was not completed which required re-terminating and torqueing of the C phase electrical connection. This issue was entered into the corrective action program as Action Request AR 289636. A senior reactor analyst performed a detailed risk evaluation for this finding. The finding was of very low safety significance (Green) because the bounding change to the core damage frequency was less than 1.0 x 10-7/year.
05000416/FIN-2012005-03	Grand Gulf	2012Q4	Failure to Implement Adequate Procedure Instructions to Perform Preventive Maintenance Requiring the Periodic Replacement of the Control Relays in GE Magne Blast Circuit Breakers	The inspectors reviewed a self-revealing non-cited violation of 10 CFR 50, Appendix B, Criterion V, Instructions, Procedures, and Drawings, for the licensees failure to complete preventive maintenance tasks on the high pressure core spray division III diesel generator output breaker in accordance with the corresponding preventive maintenance task template. The licensee entered this issue in their corrective action program as Condition Report CR-GGN-2012-07992. The immediate corrective actions included replacing the failed control relay and restoring operability to the division III diesel generator. The long term corrective actions included revising breaker refurbishment/replacement procedure with directions to replace the control relay and change the procedure frequency to every 10 years versus every 12 years. The inspectors determined that this performance deficiency was more than minor and is therefore a finding because it is associated with the equipment performance attribute of the Mitigating Systems Cornerstone and adversely affected the cornerstone objective of ensuring the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences. Specifically, this failed control relay caused the subject breaker to fail to close during the division III diesel generator monthly surveillance on June 5, 2012. The inspectors used NRC Inspection Manual Chapter 0609, Attachment 4, Initial Characterization of Findings, to determine that the issue affected the Mitigating System Cornerstone. Because the finding pertained only to a degraded condition while the plant was shutdown, the inspectors used Manual Chapter 0609, Appendix G, Shutdown Operations Significance Determination Process, Checklist 8, Cold Shutdown or Refueling Operation Time to Boil > 2 Hours: RCS Level < 23 Above Top of Flange, to determine that the finding was of very low safety significance because it did not increase the likelihood of a loss of reactor coolant system inventory; did not degrade the licensees ability to terminate a leak path or add RCS inventory when needed; did not significantly degrade the licensees ability to recover decay heat removal if lost; and did not affect the safety/relief valves (Green). The inspectors determined that the cause of this finding was a latent issue that is not reflective of current performance, therefore no cross-cutting aspect was identified.
05000461/FIN-2012004-04	Clinton	2012Q3	Evaluation of High Pressure Core Spray Test Return Line Pipe Support Failure	The inspectors reviewed operability evaluation AR 1380555, HPCS Test Return Line Hanger Damaged, related to the licensees reevaluation of HPCS test return line (1HP18C-12) without HPCS test return line pipe support 1HP06003G, which had failed and pieces were found by operators at the bottom of the suppression pool. The inspectors also reviewed the licensing basis analysis for containment penetration 1PC0033 (also termed 1MC0033). This penetration is a restraint for HPCS test return line (1HP18C-12) and was evaluated for the removal of pipe support 1HP06003G as well. As described in UFSAR Section 3.8.1.5.3, the licensing basis Code of record for containment penetration 1MC0033 is ASME Section III, 1974 Edition, Subsection NE. The ASME Design Specification for piping penetration assemblies (including containment penetrations) is DS-ME-09-CP, Piping Penetration Assemblies Design Specification, Revision 15. ASME Design Specification DS-ME-09-CP does not define a jurisdictional boundary for the piping portion that is considered part of the containment penetration. The jurisdictional boundary of the piping that is part of the containment penetration is defined by ASME Section III, Subsection NE, which states in Section NE-1131, Part C: All piping attached to containment vessel nozzles or to penetration assemblies out to and including the valve or valves required to isolate the system and provide a pressure boundary for the containment function. Such piping shall be designed for the intended service function and the containment function considered either independently or in combination as required by the Design Specification (NA-3250). The inspectors reviewed an original construction calculation (CQD-4536-IPC0033, Penetration Stress Analysis Report for Primary Containment Penetration 1PC0033, Revision 1) that was referenced by the licensee in the operability evaluation. The calculation shows a current overstress condition (i.e., applied stress > allowable stress) for the Level D faulted load condition. The applied stresses due to the level D faulted load condition are due to pipe rupture/jet impingement plus the normal operating system pressure. The design calculation for the containment penetration was identified as nuclear safety-related (Q). UFSAR Section 3.8.1.1.3 describes the safety function of the containment penetration and UFSAR Table 3.8-5 shows the location and size of the containment penetration. In response to the inspectors questions regarding the current overstress condition for the containment penetration the licensee initiated AR 01418577. The licensee also initiated AR 01417729 to address the inspectors question regarding conformance of design requirements with the ASME Code and design specification. Near the end of the inspection period, the licensee provided the inspectors additional information relevant to the containment penetration calculation determination of applied stresses due to Level D load conditions that will require additional review. Therefore, this issue is considered to be an unresolved item (URI 05000461/2012004-4, Evaluation of High Pressure Core Spray Test Return Line Pipe Support Failure) pending additional evaluation by the licensee and completion of inspector review to determine whether a nonconformance exists.
05000458/FIN-2012009-05	River Bend	2012Q3	Implementation of Vendor and Industry Recommended Relay Testing and Maintenance	The team identified an unresolved item associated with the testing of electrical lockout relays as recommended by vendor and industry guidance. River Bend Station previously tested these relays as part of a broader program to test protective relays, but the program was discontinued. In February 2011, a General Electric Type HEA61 lockout relay had failed to function and resulted in a 13.8 kV circuit breaker failing to trip and a fire. In May 2012, a second General Electric Type HEA61 lockout relay had failed to function in the feedwater pump FWS-P1B circuit breaker resulting in an initiating event. Following the May 2012 electrical fault involving the trip of main feedwater pump B, the licensee performed an extent-of-condition review of the 86 lockout relay population. River Bend Station used four different types of lockout relays in medium voltage circuits: GE HEA61 series (older style) relays GE HEA61 series (newer style) relays Electro-switch/ABB 7800 series LOR relays Electro-switch 422D949G56/Westinghouse WL relays. The failed relays in both the February 2011 event and the May 2012 event were identified as General Electric Type HEA61 relays. Of the two versions of Type HEA61 relays in use, the older style had failed in both events. During the extent-of-condition review, the licensee identified that they had approximately 187 lockout relays installed in the plant. Of these, 29 relays were the older-style General Electric Type HEA61. The relays were differentiated by the type of armature used to operate the relay, where the older style had a flat plate for the armature and the newer style had an indention on the armature plate which facilitated easier mechanical operation. During functional testing as part of the extent-of-condition testing, the licensee identified nine additional relay failures. All of the failed relays were associated with non-safety related 13.8 kV switchgear; however, the same relay type was also installed in the safety-related Division III high pressure core spray system. The licensee replaced the nine failed relays by the newer style General Electric Type HEA61 relay. The General Electric HEA lockout relay vendor manual, GEH-2058, General Electric Instructions Auxiliary Relays Type HEA61, HEA62, recommended that during any outage of the equipment and preferably at yearly intervals the relay should be tripped electrically to ensure that it is in good operating condition and that all the circuits are complete so that the associated circuit breakers can be tripped. The vendor manual also recommended that this electrical test be performed at 70 percent of rated voltage to ensure the device will actuate during low voltage conditions. The team determined that, prior to 2005, the licensee had performed testing of lockout relays as part of a broader protective relay testing program. In 2004, the licensee initiated LO-RLO-2004-00146 describing, in part, a method for performing functional testing of lockout relays as part of circuit breaker testing and updating preventive maintenance task template basis documents for circuit breakers to include the lockout relays. The action initiated to combine the functional testing of relays with circuit breaker maintenance was not effectively implemented, and, as a result, the functional testing of lockout relays was discontinued. The licensee reviewed Electro-switch Technical Publication LOR-1, A High Speed Multi- Contact Lock-Out Relay for Power Industry Applications, effective January 1, 1980, for guidance on the Electro-switch/ABB 7800 series 24 lockout relays. This document contained no specific guidance on maintenance or recommended testing. The licensees review identified that the lockout relays were used in safety-related Division I and II equipment and were regularly tested as part of the stations surveillance program. The licensee provided an excerpt from Westinghouse Descriptive Bulletin 34-252, dated May 1969 as their guidance for the Westinghouse Type WL devices. The single-page document did not provide specific guidance on maintenance or recommended testing. The licensees review identified that the WL devices were used only in non-safety related equipment. The team identified widely used industry documents that provided generic guidance on the maintenance and testing of protective relays including Electrical Power Research Institute EPRI NP-7216s, Protective Relay Maintenance and Application Guide, which provided guidance for implementing a protective relay maintenance program and included descriptions of recommended electrical and functional checks. The team assessed the licensees overall plan and schedule for lockout relay inspections following the May 2012 event. The team determined the plan and schedule for testing functionality of the lockout relays was appropriate as the licensee was testing all of the older style General Electric HEA61 relays, had validated functionality of other styles of lockout relays by surveillance testing the associated equipment or analysis, and would test any remaining lockout relays when plant risk conditions allowed. The team determined that the corrective actions identified were appropriate and timely, and the licensee had adequately considered safety significance in their planning process. The team concluded that additional inspection is required to assess the lack of vendor and industry recommended maintenance activities at River Bend Station on lockout relays associated with medium voltage circuit breakers since 2005.
05000458/FIN-2012003-03	River Bend	2012Q2	High Pressure Core Spray Diesel Generator Bearing Lubrication Deficiencies	The inspectors identified a non-cited violation of 10 CFR Part 50, Appendix B, Criterion XVI, Corrective Action, for failing to correct a condition adverse to quality for lubricating the high pressure core spray diesel generator bearings. The station documented the finding in Condition Report CR-RBS-2012-02666. This performance deficiency was more than minor and was a finding because, if left uncorrected, inadequate lubrication work instructions could cause bearing failure due to inadequate lubrication or generator winding failure due to grease intrusion into the electrical windings in the generator. The significance of this finding was evaluated using a Phase 1 significance determination process screening and was determined to be of very low safety significance (Green) because it was not a design or qualification deficiency; did not represent a loss of system safety function; and did not screen as potentially risk significant due to seismic, flooding, or severe weather initiating events. The apparent reason the initial condition report was closed without correcting the work instruction to lubricate the high pressure core spray diesel generator bearings was that personnel who prepared and approved the operability evaluation were focused on proving operability not correcting a condition adverse to quality. Their focus was specific to the components ability to perform its function and not on completely identifying the issue in the corrective action program. Therefore, the finding has a cross-cutting aspect in the area of problem identification and resolution associated with the corrective action program component because the station did not identify this issue completely, accurately, and in a timely manner commensurate with its safety significance
05000416/FIN-2012003-05	Grand Gulf	2012Q2	Failure to Follow a Post-Modification Test Procedure	The inspectors identified a non-cited violation of 10 CFR Part 50, Appendix B, Criterion V, Instructions, Procedures, and Drawings, involving the licensees failure to follow a post-modification test procedure for the interconnecting siphon line between the two standby service water system cooling tower basins. Operability of the ultimate heat sink is based on a minimum water level in the two standby service water cooling tower basins, an operable interconnecting siphon between the basins, and four operable cooling tower fans (two per basin). At extended power uprate conditions, the configuration of the basins and the original siphon line would not support 30 days of operation of both trains of the standby service water system and the high pressure core spray service water systems without makeup, so the licensee performed a modification (EC 25649), which involved replacing the original siphon line with a new siphon line in order to transfer water from one basin to the other. On March 28, 2012, after completing the modification, the licensee performed post-modification testing to determine the piping friction loss coefficient of the modified siphon line and to evaluate its acceptability against the worst-case friction loss coefficient documented in EC 25649. The licensee deviated from the test procedure, as-written, and performed the test with an inadequate pressure gauge instead of the specified gauge. After inspectors challenged the validity of these test results, the licensee performed another test of the siphon line with a different method that did not require the use of a pressure gauge to measure the piping friction loss coefficient. The inspectors reviewed the subsequent test data and found the test results to be satisfactory. The licensee documented this concern in Condition Report CR-GGN-2012-05260. The finding is more than minor because it is associated with the design control attribute of the Mitigating Systems Cornerstone and adversely affected the cornerstone objective to ensure availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences (i.e., core damage). Specifically, the use of an unqualified gauge invalidated the test results, and a different test method had to be developed to determine the piping friction loss coefficient for the siphon line. The inspectors evaluated this finding using Inspection Manual Chapter 0609, Attachment 4, Phase 1 Initial Screening and Characterization of Findings, and determined that the finding was of very low safety significance (Green) because the finding was not a design or qualification deficiency confirmed to result in loss of operability or function; did not represent a loss of safety system function; did not represent actual loss of safety function of a single train for greater than its technical specification allowed outage time; and did not screen as potentially risk significant due to a seismic, flooding, or severe weather initiating event. The finding had a cross-cutting aspect in the human performance area associated with work practices component because licensee personnel proceeded in the face of uncertainty or unexpected circumstances. Specifically, the licensee proceeded with the test without verifying that the pressure gauge was suitable for the test conditions after observing unexpected measurements with the gauge.
05000397/FIN-2012002-06	Columbia	2012Q1	Licensee-Identified Violation	Title 10 CFR 50.65(a)(4) states, in part, that before performing maintenance activities, the licensee shall assess and manage the increase in risk that may result from the proposed maintenance activities. Contrary to the above, on February 27, 2012, the high pressure core spray system was made unavailable during surveillance testing without performing a risk assessment prior to conducting testing. The documented the issue in the corrective action program as Action Request AR 258712. This violation is of very low safety significance because the risk deficit during the time of the surveillance was calculated to be less than 1.0E-6.
05000373/FIN-2011005-01	LaSalle	2011Q4	Failure to Promptly Identify and Correct an Oil Leak on the HPCS Waterleg Pump	A finding of very low safety significance and associated NCV of Title 10 of the Code of Federal Regulations (CFR) Part 50, Appendix B, Criterion XVI, Corrective Action, was identified by the inspectors for the failure to promptly identify and correct a condition adverse to quality. Specifically, on November 8, 2011, the inspectors identified that the oil reservoir on the Unit 1 high pressure core spray (HPCS) waterleg pump was empty, with a soiled oil-absorbent pad positioned beneath it. The licensee had previously identified a leak from the reservoir and placed the pad beneath it, but did not enter the problem into the corrective action program (CAP) and did not repair the leak. Upon notification of the condition by the inspectors, the licensee immediately entered this issue into the CAP, verified operability of the HPCS system, restored the oil level, established a special log to monitor the leak, and shortly thereafter replaced the waterleg pump. Additionally, the licensee was conducting an apparent cause evaluation to determine the causes of the occurrence and to develop additional corrective actions. The finding 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. The finding was determined to be of very low safety significance because there was no design deficiency, no actual loss of safety function, no single train loss of safety function for greater than the technical specification (TS) allowed outage time, and no risk significance due to external events. This finding has a cross-cutting aspect in the area of problem identification and resolution, corrective action program, for the failure to maintain a low threshold for identifying issues within the CAP commensurate with their safety significance
05000458/FIN-2011008-04	River Bend	2011Q4	Station Blackout-Containment Venting	The team reviewed Condition Report CR-RBS-2011-03471, concerning River Bend Station\\\'s severe accident management program associated with 4-hour station blackout coping duration issues. As documented in Condition Report CR-RBS2011- 03471, Abnormal Operating Procedure, AOP-0050, Station Blackout, provided instructions for venting pressurized containment vapor to the annulus through a 3-inch hardened vent path. However, the licensee\\\'s evaluation of these actions determined that the hardened vent path was too small to prevent containment over pressurization in an extended station blackout greater than the 4-hour coping period. It can delay but not prevent containment failure which is calculated to occur at 50-55 psia approximately 16 hours into an extended station blackout. Based on the licensee\\\'s analysis Calculation 813.18.12.4-030, the operator actions which specified venting containment through the containment/hydrogen purge ventilation system components have been deleted from Abnormal Operating Procedure, AOP-0050 and revised in Emergency Operating Procedure, EOP-0005 because of the potential personnel hazards. The licensee\\\'s revised station blackout coping strategy involves venting through one of the containment personnel airlocks and out to the environment through an open auxiliary building door. In order to support the revised venting through one of the containment personnel airlocks to the environment described in procedures AOP-0050 and EOP-0005, the licensee performed a 10 CFR 50.59 review for these procedures. Based on the results of this review, both of these procedural changes were screened out and a 10 CFR 50.59 evaluation was not performed. Calculation G13.18.12.4*4, Revision 0, evaluated the conditions in containment resulting from a station blackout of indefinite length with reactor core isolation cooling and high pressure core spray as the only available makeup sources. The team reviewed the respective cases described in this calculation and determined that several of these cases resulted in exceeding the heat capacity temperature limit prior to the 4-hour station blackout coping limit. Accordingly, containment venting currently described in procedures AOP-0050 and EOP-0005, through the containment air-lock would be initiated before the 4-hour coping time. Based on these reviews, the team determined that the licensing basis for containment and the associated systems including the containment personnel airlock described in the updated safety analysis report are to maintain containment integrity during and following a design basis accident. Additionally, the team determined that the use of the personnel airlock as a vent path to depressurize containment during a station blackout event did not appear to be described in any of the available licensing basis documents. Accordingly, the team views that the licensee\\\'s strategy of venting through one of the containment airlocks and out to the environment through an open auxiliary building door appears to represent an unreviewed safety question. The inspectors determined that more inspection is necessary to resolve the issue. Since more information is necessary, the issue is considered an unresolved item pending further NRC review.
05000397/FIN-2011006-02	Columbia	2011Q3	Three Examples of a Failure to Follow Procedures Results in Unsecured Transient Equipment and Ineffective Corrective Actions	The team identified three examples of a Green noncited violation of 10 CFR Part 50, Appendix B, Criterion V, Instructions, Procedures, and Drawings, for the failure to follow station procedures. The licensee entered these examples into the corrective action program as Action Request/Condition Report 249287. The first example was a failure to properly implement the instructions of the station\'s seismic procedure, PPM 10.2.53, to evaluate and control transient equipment and materials. Specifically, during this inspection, on August 29 through September 1, 2011, the team identified unsecured bookcases, rolling metal ladders, and loose maintenance carts in the main control room, and barrels stored near a high pressure core spray pump that were not evaluated in accordance with seismic procedures. The second example was the failure to perform a root cause analysis for long standing problems that have had ineffective corrective actions, as required by Procedure SWP-CAP-06, Condition Review Group (CRG), Revision 16, Specifically, between October 2007, and September 15, 2011, multiple examples of the failure to follow seismic procedures have been identified by past NRC inspection teams and licensee internal follow-up actions. Therefore, the team concluded Energy Northwest failed to recognize that a root cause analysis was required to address this long standing issue. The third example was a failure to promptly implement interim corrective actions as required by Procedure SWP-CAP-01 ,Corrective Actions Program. Specifically, after the team identified the improperly stored items on September 1, 2011, the licensee secured the material, but failed to implement any interim corrective actions to reduce the likelihood that the condition would not be repeated until longer term corrective actions could be implemented. On September 13, 2011, when the team asked the licensee about interim corrective actions, the licensee conducted a site stand-down to inform station personnel about the condition and procedural requirements. The finding was more than minor because it was a programmatic deficiency, which affected the Mitigating Systems Cornerstone objective, and if left uncorrected, could lead to a more significant safety concern because a seismic event could result in the unavailability of systems used to mitigate the consequences of initiating events. Using Inspection Manual Chapter 0609.04, Phase 1 - Initial Screening and Characterization of Findings, the finding was determined to have very low safety significance (Green) because it did not result in an actual loss of a system safety function, did not result in a loss of a single train of safety equipment for greater than its technical specification allowed outage time, did not involve the loss or degradation of equipment specifically designed to mitigate a seismic, flooding, or severe weather initiating event, and did not involve the total loss of any safety function that contributes to an external event initiated core damage accident sequence. In addition, this finding had a crosscutting aspect in the area of human performance, associated with the work control component, because the licensee failed to appropriately plan work on multiple occasions, resulting in job site conditions which may have impacted plant components (H.3(a)).
05000416/FIN-2011003-09	Grand Gulf	2011Q2	Licensee-Identified Violation	Title 10 CFR Part 50, Appendix B, Criterion V, Instructions, Procedures and Drawings, states, in part, that activities affecting quality shall be accomplished in accordance with prescribed procedures. Specifically EN-OP-104, Operability Determination Process, Revision 5, Section 5.3(1), states in part to Confirm the existence of a Degraded or Nonconforming Condition for the Technical Specification System Structure or Component. Contrary to this requirement, on March 18, 2011, the on-shift senior reactor operator failed to perform a proper operability determination for the high pressure core spray pump after minimum flow valve 1E22-F012 cycled approximately 11 times during testing causing the supply breaker to trip open, resulting in high pressure core spray being inoperable. After resetting the breaker for 1E22-F012, ensuring the breaker was not faulted, and performing a one-time stroke test, the system was declared operable. Engineering personnel evaluated the event several hours later and questioned the operability of valve 1E22-F012 and the high pressure core spray system due to repeated cycling of the valve motor, which resulted in the breaker tripping. Based on engineering input, operations performed a second operability determination and determined that the system was operable with evaluation required. The licensee performed testing of the breaker for valve 1E22-F012 and determined its over-current trip setting had drifted to approximately 60 amps when its minimum allowed setting was 85 amps. This confirmed that the high pressure core spray system was inoperable the entire time. This issue was entered into the licensees corrective action program as Condition Report CR-GGN-2011-02240. The finding was determined to be of very low safety significance (Green) because it was not a design or qualification deficiency, did not represent a loss of a system safety function, and did not screen as potentially risk significant due to a seismic, flooding, or severe weather initiating event.
05000416/FIN-2011003-05	Grand Gulf	2011Q2	Failure to Provide Adequate Procedures for High Pressure Core Spray Minimum Flow Valve Surveillance Testing	The inspectors reviewed a self-revealing noncited violation of Technical Specification 5.4.1.a for the licensees failure to provide adequate testing procedures, which resulted in the high pressure core spray minimum flow valve inadvertently stroking approximately 11 times during a surveillance test. The excessive stroking of the valve resulted in the unplanned inoperability of the high pressure core spray system because the valves feeder breaker overcurrent instantaneous trip setpoint had drifted below the manufacturers tolerance for the existing setting. As immediate corrective action, the licensee replaced the degraded breaker. This finding was entered into the licensees corrective action program as Condition Report CR-GGN-2011-01901. The finding is more than minor because it is associated with the procedure quality attribute of the Mitigating Systems Cornerstone and adversely affected the cornerstone\'s 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, inspectors determined that the finding was of very low safety significance (Green) because it did not result in a loss of system safety function since the high pressure core spray system would still have been functional even with the minimum flow valve potentially failing open. Additionally, it did not represent a 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 had a cross-cutting aspect in the area of problem identification and resolution associated with operating experience in that licensee had not incorporated operating experience from a similar event that had occurred at another Entergy site.
05000373/FIN-2011002-01	LaSalle	2011Q1	Failure to Post Protected Pathway Signs for a Red Risk Path System	A finding of very low safety significance and associated NCV of 10 CFR 50.65(a)(4), Maintenance Rule, was identified by inspectors for the licensees failure to implement all necessary prescribed risk management actions during a Unit 2 Reactor Core Isolation Cooling (RCIC) system maintenance window. Specifically, the licensee failed to post protected equipment signs for the Unit 2 systems whose unavailability would have taken the unit into a Red risk condition. The licensee entered this issue into their corrective action program (CAP). The inspectors determined that this performance deficiency is a finding and greater than minor because the licensee failed to implement prescribed compensatory measures of posting signs and barricades to protect the high pressure core spray (HPCS) equipment during the RCIC work window, hence degrading the HPCS safety function during this time; which is similar to Example 7.g in IMC 0612, Appendix E. The inspectors performed a Phase 1 screening with assistance from the Regional Senior Reactor Analyst (SRA) using IMC 0609, Appendix K, Maintenance Risk Assessment and Risk Management Significance Determination Process, Flowchart 2, Assessment of Risk Management Actions. The calculated change in Incremental Core Damage Probability (ICDP), or actual increase in risk during this work window, was 5.7x10-9, and the incremental large early release probability (ILERP), was 3.3x10-10. In accordance with Flowchart 2, since the ICDP was less than 1x10-6 and the ILERP was less than 1x10-7, the finding screened as Green. This finding has a cross-cutting aspect in the area of Human Performance, Work Practices, because the licensee failed to conduct first and second verifications and use independent peer checks or other human error prevention techniques when evaluating risk-significant and/or Technical Specification (TS)-related activities, which led to the missed postings for the protected pathway equipment (H.4(a)).
05000458/FIN-2010005-02	River Bend	2010Q4	Two Examples of Completing Maintenance that Affected the Performance of Safety-Related Equipment but Was Not Properly Preplanned	The inspectors reviewed a two-example self-revealing green noncited violation of Technical Specification 5.4.1 for two occasions on which the licensee completed maintenance that affected the performance of safety-related equipment (high pressure core spray) but was not properly preplanned and performed in accordance with written procedures, documented instructions, or drawings appropriate to the circumstances As a result, the licensee overtorqued the high pressure core spray lower motor bearing drain plug causing the plug to fracture. This fracture resulted in excessive oil leakage that caused the pump to become inoperable. The violation is in the licensees corrective action program as Condition Report CR-RBS-2011-00224 These performance deficiencies were more than minor and therefore constituted a finding because they affected the equipment performance attribute of the Mitigating Systems Cornerstone, and adversely affected the cornerstone objective of ensuring the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences. As described in Inspection Manual 0609 Appendix A, a Phase 2 analysis using the presolved worksheet determined that this finding had very low risk significance. The finding has a crosscutting aspect in the resources component of the human performance area because the apparent cause of the finding was a procedure that was not adequate to assure nuclear safety.
05000458/FIN-2010005-01	River Bend	2010Q4	Failure to Develop a Preventive Maintenance Schedule to Specify Inspection or Replacement of the O-Ring in the High Pressure Core Spray Lower Motor Bearing Drain Plug	The inspectors reviewed a self-revealing noncited violation of Technical Specification 5.4.1 for the licensees failure to determine the appropriate preventive maintenance strategy and task frequency for the o-ring in the high pressure core spray lower motor bearing drain plug. As immediate correction action, the licensee replaced the o-ring. At the conclusion of the inspection, the licensee was in the process of determining the appropriate replacement frequency. The licensee entered this issue into their corrective action system as Condition Report CR-RBS-2010-05766. This finding was more than minor because, if left uncorrected, it had the potential to lead to a more significant safety concern, in that if the licensee did not develop a preventive maintenance schedule for periodically replacing the subject o-ring, degradation of that o-ring due to aging could allow a leak that would drain oil from the lower motor bearing and thus render the high pressure core spray pump inoperable. As described in Inspection Manual 0609 Appendix A, a Phase 2 analysis using the presolved worksheet determined that this finding had very low (Green) risk significance. This finding has a crosscutting aspect in the operating experience component of the problem identification & resolution area because the licensee did not systematically collect, evaluate, and communicate to affected internal stakeholders in a timely manner relevant internal and external operating experience.
05000373/FIN-2010005-02	LaSalle	2010Q4	Failure to Foolow Performance Centered Monitoring Process Procedure	A finding of very low safety significance (Green) and an associated NCV of Technical Specification (TS) 5.4.1, Procedures, was self-revealed, for the failure to follow procedural guidance specified in procedure MA-AA-716-210, Performance Centered Monitoring Process. Specifically, a control relay for the Unit 2 Division 3 switchgear room ventilation was inappropriately classified for its preventive maintenance schedule and had a recommended replacement frequency of as required instead of the 10 year frequency required, by procedure, for this type of equipment. As a result, when this relay failed, it caused the switchgear room ventilation system (VD) to trip and the unexpected unavailability and inoperability of the Unit 2 high pressure core spray (HPCS) system. The inspectors determined that the finding was of more than minor significance because it affected the Mitigating Systems Cornerstone attribute of Human Performance (human error pre-event), and it affected the cornerstone objective to ensure availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences. Specifically, since HPCS is a single train, this constituted a loss of safety function. The finding was determined to be of very low safety significance using an SDP Phase 3 analysis. As part of the corrective actions for this issue, the licensee re-classified the control relay to Critical, high duty cycle, to help ensure that replacement of the component occurs at the appropriate time-based frequency. The inspectors did not identify a cross-cutting aspect associated with this finding.
05000458/FIN-2010004-05	River Bend	2010Q3	Inadequate High Pressure Core Spray Pump Room Cooler Bearing Maintenance	A self-revealing, very low safety significance (Green) noncited violation 10 CFR 50, Appendix B, Criterion V, Instructions, Procedures, and Drawings, was reviewed for the licensees failure to prescribe lubrication and installation of bearings on the high-pressure core spray room cooler motors by adequate procedures. In response to this finding, the licensee changed their procedure for performing material equivalency evaluations to require that, when plant components change and associated vendor-recommended maintenance schedules change, licensee personnel also update the corresponding preventivemaintenance tasks. The licensee entered this issue into their corrective action program as Condition Report CR-RBS-2010-02919. This finding was more than minor because it was associated with the equipment performance attribute of the Mitigating Systems Cornerstone and adversely affected the cornerstone objective to ensure the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences, in that this finding caused inoperability of the high-pressure core spray. The significance of this finding was determined by completing a Phase 3 analysis in accordance with Inspection Manual Chapter 0609, Appendix A, which determined that the incremental core damage probability maximum was 2x10-7, and that the finding was therefore of very low safety significance (Green). This finding did not represent current licensee performance and consequently did not have a cross-cutting aspect because the cause of this finding was that when the licensee replaced a component by a similar component from a different vendor, no licensee procedure required them to update the associated maintenance frequencies, and because before this finding was identified, the licensee had no reasonable opportunity to identify and correct that deficiency in that procedure. (Section 1R19)
05000458/FIN-2010003-01	River Bend	2010Q2	Inadequate Risk Assessment for High Pressure Core Spray Pump Room Unit Cooler Maintenance	The inspectors identified a noncited violation of 10 CFR 50.65(a)(4) involving the licensees failure to perform an adequate risk assessment while the high pressure core spray room unit cooler was unavailable. Specifically, the licensee assumed that risk would remain green and high pressure core spray would continue to inject into the reactor vessel for 6 hours after room cooling was made unavailable, when, in fact, risk became yellow because high pressure core spray would become unreliable after approximately 60 minutes due to instrument failure in the pumps minimum flow logic. As immediate corrective action, the licensee issued a standing order that administratively considered high pressure core spray unavailable when its room cooler is removed from service. The licensee entered this issue into their corrective action program as Condition Report CR-RBS-2010-02937 This issue was more than minor because it was associated with the equipment performance attribute of the Mitigating Systems Cornerstone and adversely affected the 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, Significance Determination Process, Appendix K, Maintenance Risk Assessment and Risk Management Significance Determination Process, the finding is determined to have very low safety significance (Green) because the incremental core damage probability deficit for the affected time period is less than 1.0E-6 and because the licensee used incorrect risk assumptions that changed the outcome of their risk assessment. There is no crosscutting aspect associated with this violation because the assumptions that lead to the performance deficiency are not indicative of current licensee performance.
05000461/FIN-2009005-04	Clinton	2009Q4	Failure to Correctly Install Relays Inside of the Division 3 Diesel Generator Control Panel	A finding of very low safety significance with an associated Non-Cited Violation of 10 CFR 50, Appendix B, Criteria V, Instructions, Procedures, and Drawings, was self-revealed on September 23, 2009, when the Division 3 diesel generator (DG) was found to have had two components installed incorrectly. Electrical maintenance technicians had incorrectly replaced time delay relays K-8A and K-32 on September 24, 2007, essentially swapping the locations of the two relays. This rendered the Division 3 DG inoperable for about two years and resulted in a loss of safety function for the Division 3 DG and high pressure core spray system under a certain sequence of initiating events. As immediate corrective action, the licensee restored the two time delay relays to the correct configuration and immediately verified that the remaining time delay relays inside the Division 3 DG Control Panel were in their proper locations. The finding was of more than minor significance because, if left uncorrected, it would potentially lead to a more significant safety concern (i.e., the inoperability of risk-significant plant safety systems). In addition, based on review of Example 5c in Inspection Manual Chapter 0612, Power Reactor Inspection Reports, Appendix E, Examples of Minor Issues, the issue would be considered to be of more than minor significance because the incorrect relays were installed in the control panel. Although the finding resulted in a loss of safety function for the Division 3 DG and high pressure core spray system, it was determined to be of very low safety significance during a Phase 2 Significance Determination Process review considering the very limited conditions (i.e., only for 45 seconds following shutdown of the engine concurrent with a design basis accident) when the Division 3 DG was incapable of performing its safety function. The resultant exposure time was estimated to be about 27 minutes during the 2-year period. The inspectors concluded that this finding affected the cross-cutting area of human performance because the licensee did not effectively communicate expectations regarding procedural compliance and; as a result, maintenance technicians did not follow their procedures by installing nonconforming components and restoring the safety system to service. (IMC 0305 H.4(b)
05000220/FIN-2009004-01	Nine Mile Point	2009Q3	Unqualified HPCS Pump Power Cables Used in Submerged Conditions	An NRC-identified non-cited violation (NCV) of 10 CFR Part 50, Appendix B, Criterion III, Design Control, was identified, in that Nine Mile Point Nuclear Station (NMPNS) failed to maintain the Unit 2 high pressure core spray (HPCS) pump power cables in an environment for which they were designed. Although NMPNS had indications that these cables were periodically submerged in water, they could not demonstrate that the cables were designed for submerged conditions. As immediate corrective action, NMPNS dewatered and inspected the HPCS cable run, and changed the frequency of dewatering to monthly. Based on the inspection results, along with the cable design specifications and most recent test results, NMPNS concluded that the HPCS pump power cables would remain operable while they conduct a design change evaluation to examine methods to reduce cable exposure to submerged conditions. The issue was entered into the corrective action program (CAP) as condition report (CR) 2009-2901.The finding was more than minor because, if left uncorrected, it had the potential to lead to a more significant safety concern. The finding affected the equipment performance attribute of the Mitigating Systems cornerstone objective to ensure the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences. The finding was of very low safety significance because it was a qualification deficiency that did not result in loss of operability. The finding had a cross-cutting aspect in the area of problem identification and resolution, operating experience, because NMPNS did not use operating experience, such as Generic Letter (GL) 2007-01, Inaccessible or Underground Power Cable Failures That Disable Accident Mitigation Systems or Cause Plant Transients, to evaluate possible adverse effects of periodic submergence of the HPCS pump power cables (P.2.a per IMC 0305).
05000440/FIN-2009003-04	Perry	2009Q2	Failure to Prevent Contact of Energized Components Renders RCIC System Inoperable	A finding of very low safety significance (Green) and associated non-cited violation of Technical Specification (TS) 5.4.1 was self-revealed when technicians failed to implement actions to prevent shorting of energized electrical components during maintenance. Specifically, during surveillance testing activities, a lifted lead shorted to a test lug causing the reactor core isolation cooling (RCIC) Division 2 logic to trip. The technicians suspended their surveillance procedure and operators restored the RCIC system in accordance with licensee procedures. Operators also verified high pressure core spray (HPCS) was operable. The licensee visually inspected the RCIC system and found no apparent damage. The licensee conducted additional training on the use of error prevention tools and entered the issue into the corrective action program as CR 09 59356.The finding was determined to be more than minor because the finding was associated with the Mitigating Systems cornerstone attribute of equipment performance and affected the cornerstone objective to ensure the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences. Specifically, the short circuit resulted in the RCIC system being inoperable. The finding was determined to have very low safety significance because it did not represent a loss of system safety function, a loss of safety function of a non-TS train designated as risk-significant for greater than 24 hours, an actual loss of safety function of a single train for greater than its TS-allowed outage time, or screen as potentially risk-significant due to a seismic, flooding, or severe weather initiating event. This finding has a cross-cutting aspect in the area of human performance per IMC 0305 H.4(a) because the technician failed to use error prevention techniques, such as self-checking, that are commensurate with the risk of the assigned task. Specifically, he did not use \'STAR\' (Stop, Think, Act, Review) during an activity that could render the RCIC system inoperable
05000416/FIN-2009003-02	Grand Gulf	2009Q2	Inadequate Operability Evaluation for Debris Left in the Condensate Storage Tank	The inspectors identified a Green noncited violation of 10 CFR Part 50Appendix B, Criterion V involving a failure to follow procedures which resulted in an inadequate operability evaluation. During the week of May 18, 2009, the site conducted debris removal in the condensate storage tank. This debris removal was necessary because of a failure to remove all debris in the condensate storage tank during their spring 2007 cleanup project. The licensee performed an operability evaluation for objects left in the condensate storage tank which stated that the high pressure core spray system and reactor core isolation cooling would remain operable for all postulated events. Upon review by the inspectors, the operability evaluation did not address several issues including objects left in the condensate storage tank and condensate system return flow to the condensate storage tank following a plant shutdown/scram. The licensee entered this issue into their corrective action program as Condition ReportsCR-GGN-2009-02815 and CR-GGN-2009-02837.This finding is more than minor because the failure to perform an adequate operability evaluation, if left uncorrected, could become a more significant safety concern. Using the Manual Chapter 0609, Significance Determination Process, Phase 1 Worksheet, this finding was of very low safety significance since it did not result in a loss of operability, nor did it screen as potentially risk significant due to a seismic, flooding, or severe weather-initiating event. The cause of this finding had a crosscutting aspect in the area of problem identification and resolution associated with corrective actions because licensee personnel failed to thoroughly identify all materials left in the condensate storage tank during their original operability determination
05000416/FIN-2009006-04	Grand Gulf	2009Q2	Inadequate Corrective Actions for Replacement of Safety-Related Batteries	The team identified a noncited violation of 10 CFR Part 50, Appendix B, Criterion XVI, Corrective Actions, for failure to identify and correct a condition adverse to quality related to the seismic qualification of the Division III High Pressure Core Spray safety-related battery. Specifically, the licensee failed to identify an incorrectly installed end bracket after replacement of the Division III safety-related battery in 2002 using procedures, work instructions, and drawings that were supposed to have been corrected after this same issue was identified during a 1997battery replacement activity. The licensee has entered this into their corrective action program as CR-GGN-2009-00830.This finding was more than minor because it affected the mitigating systems cornerstone attribute of external events for ensuring the availability, reliability, and capability of systems that respond to initiating events. Also, using Inspection Manual Chapter 0612, Power Reactor Inspection Reports, Appendix B, Section 1-3,Screen for More than Minor ROP, question 2, the finding is more than minor because if left uncorrected, the performance deficiency would have the potential to lead to a more significant safety concern. Using the Inspection Manual Chapter0609, Significance Determination Process, Phase 1 Worksheets, the finding was determined to have very low safety significance (Green) because it was confirmed to not result in a loss of operability or functionality. The finding was reviewed for crosscutting aspects and none were identified
05000440/FIN-2009002-06	Perry	2009Q1	Maintenance on HPCS System resulted in Emergency Operating Procedure Entry	A finding of very low safety significance and associated NCV of Technical Specification Section 5.4.1 was self-revealed on February 3, 2009, when the control room received an unexpected high pressure core spray (HPCS) pump room sump level high alarm and entered Emergency Operating Procedure (EOP) 3, Secondary Containment Control. The licensee did not properly control a maintenance activity on the HPCS system resulting in unexpected water spray in the HPCS pump room. As part of their immediate corrective actions, licensee personnel recovered from the drain down of the system and entered the issue into their corrective action program. This finding was considered more than minor because it was associated with the human performance attribute of the Initiating Events cornerstone and adversely affected the cornerstone objective of limiting the likelihood of events that upset plant stability. The event challenged shutdown operations as operators entered the EOP and responded to reports of significant water spray entering the pump room. The finding was determined, through an SDP analysis, to be of very low safety significance as no mitigation equipment or functions were affected. The primary cause of this finding was related to the cross-cutting aspect in the area of Human Performance per IMC 0305 H.3(a)because the organization failed to appropriately plan work activities that impact plant structures and systems, and failed to ensure appropriate contingencies were in place to perform a maintenance activity
05000458/FIN-2008004-03	River Bend	2008Q3	Inadequate Risk Assessment for Transformer Yard Maintenance While Shut Down	The inspectors identified a noncited violation of 10 CFR 50.65(a)(4) involving the licensees failure to assess and manage the increase in risk that may result from proposed maintenance activities. Specifically, while conducting maintenance in the transformer yard during severe weather with high pressure core spray inoperable, the licensee did not assess the affects on the shutdown risk. The licensee entered this issue into their corrective action program as Condition Report CR-RBS-2008-05383. The inspectors determined this finding was more than minor since it was similar to Manual Chapter 0612, Appendix E, Example 7.e, and since it caused the licensees risk model to change from a Green to Yellow risk window. In accordance with NRC Inspection Manual Chapter 0609, Appendix K, Maintenance Risk Assessment and Risk Management, the inspectors requested that a senior reactor analyst evaluate the risk of this condition. The analyst determined that this finding was of very low risk significance because the associated risk deficit was less than 1.0E-6 (Section 1R13).
05000440/FIN-2008004-09	Perry	2008Q3	Licensee-Identified Violation	10 CFR Part 50, Appendix B, Criterion XI, Test Control, requires, in part, that a test program shall be established to assure that all testing required to demonstrate that structures, systems, and components will perform satisfactorily in service is identified and performed in accordance with written test procedures which incorporate the requirements and acceptable limits contained in applicable design documents. Contrary to this, on July 21, 2007, the licensee failed to test the C Emergency Service Water pump discharge valve for seat leakage following valve replacement. This resulted in high pressure core spray system inoperability and unavailability in May 2008 due to low keep-fill system pressure. Immediate corrective actions included repair of the affected valve. The finding was determined to be of very low safety significance because the system unavailability time was less than three days. (CR 08-40969
05000416/FIN-2008002-07	Grand Gulf	2008Q1	Inadequate Design Control of HPCS Minimum Flow Valve MOTOR-OPERATED Valve Over Current Setpoint	The inspectors identified a self-revealing noncited violation of 10 CFR Part 50, Appendix B, Criterion III, \"Design Control,\" for failure to properly set the over current trip setpoint for the high pressure core spray minimum flow motor operated valve. This resulted in a spurious over current trip of the valve breaker during a high pressure core spray momentary pump start for breaker operability following post Division 3 emergency core cooling system testing. As a result of the trip, the high pressure core spray minimum flow valve failed open. This issue was entered into the licensees corrective action program as Condition Report CR-GGN-2008-01201. The finding was more than minor because it was associated with the barrier integrity cornerstone to provide reasonable assurance that the physical design barriers protect the public from radionuclide releases caused by accidents or events. Using the MC 0609, \"Significance Determination Process,\" Phase 1 worksheet, the finding was determined to have very low safety significance since it did not result in a loss of the containment barrier. Additionally, the issue was screened and determined to not impact the High Pressure Core Spray mitigating system function (Section 4OA3)

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