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| Quarter | Site | Title | Description | |
|---|---|---|---|---|
| 05000261/FIN-2013003-01 | 2013Q2 | Robinson | Failure to Scope in all CVCS Instruments used in EOPs in the maintenance rule program | The inspectors identified a Green NCV of 10 CFR 50.65(b)(2), Requirements for Monitoring the Effectiveness of Maintenance at Nuclear Power Plants, because the licensee failed to scope in all the Chemical Volume and Control (CVCS) instruments used in plant Emergency Operating Procedures (EOPs). Specifically, the CVCS instrument loops for FI-110, Boric Acid Bypass Flow, FI-122A, Charging Flow and LI-115, volume control tank (VCT) Level, were not included in the maintenance monitoring program. Subsequent review by the licensee identified one additional functional failure that was previously unrecognized. The licensee entered the issue into their corrective action program (CAP) as Nuclear Condition Report (NCR) 574956. The licensee corrective actions included adding the associated instruments loops to the maintenance rule program and revising the performance monitoring criteria. The inspectors determined that the failure to scope in all the CVCS instruments, used in EOPS, into the maintenance rule program was a performance deficiency. The finding was more than minor because if left uncorrected, the performance deficiency would have had the potential to lead to a more significant safety concern. Specifically, the failure to scope in all CVCS instruments into the maintenance rule program could affect the maintenance rule programs ability to effectively monitor the performance of CVCS equipment and the accomplishment of EOPs. This finding was considered to have very low safety significance (Green) because the finding did not cause a loss of mitigation equipment functions and did not represent an actual loss of function of one or more non-Tech Spec Trains of equipment designated as high safety-significant in accordance with the licensees maintenance rule program for greater than 24 hours. The finding does not have a cross-cutting aspect since the failure to scope this equipment into the maintenance rule program was not recognized during the initial maintenance rule scoping activities and as a result, is not indicative of current performance. |
| 05000261/FIN-2013003-02 | 2013Q2 | Robinson | Failure of B EDG Recirculation Damper in the Open Position Results in EDG Inoperability | An Unresolved Item was identified regarding the discovery of HVS-5, B Emergency Diesel Generator Recirculation Damper failed in the open position. The URI is being opened to provide for additional inspection of the cause of the failure and to review the licensees apparent cause evaluation. On May 1, 2013, B Emergency Diesel Generator Heating and Ventilation System Recirculation damper was found failed in the open position. Visual inspections by engineering determined that the actuator linkage was bent and contacting adjacent ductwork. This condition was identified during a walkdown of HVS-5 RECIRC-DMP following questions by inspectors regarding the position of the damper and operators ability to properly monitor the damper position during EDG surveillance testing. Following the discovery of this issue, operations declared the B EDG inoperable and took immediate corrective actions to close the damper. The HVS-5-RECIRC damper is designed to open when the B EDG is in operation and outside ambient temperature is below approximately 50F. When outside ambient temperatures are above 60F, with the EDG in service, the recirculation damper is designed to be fully closed to prevent air circulation back to the B EDG room supply fan and ensure the diesel room design limit temperature, of 130F, is not exceeded. The licensees initial investigation determined that the failure was associated with inadequacies in the original equipment design of the air actuator and damper linkage. The air actuator was replaced on October 22, 2012, as part of an engineering change to replace obsolete and aging air motors in safety related systems. At the time of discovery, outside ambient temperature was 78F. Engineering performed a past operability evaluation and determined that based on the open damper position and a historical review of outside ambient temperatures between October 22, 2012 to May 1, 2013, the component design limit temperature for the B EDG would not have been exceeded. At the end of the inspection period, inspectors had additional questions regarding vendor guidance for installation of the air motor and previously identified damper failures. Additional inspection time is required to review the licensees apparent cause evaluation. This issue will be identified as URI 05000261/2013003-02, Failure of B EDG Recirculation Damper in the Open Position Results in EDG Inoperability. |
| 05000261/FIN-2012005-02 | 2012Q4 | Robinson | Failure to Effectively Implement Gas Intrusion Program | The inspectors identified a Finding for the licensees failure to perform the 18- month pre-refueling outage (RO) ultrasonic testing (UT) examinations on 47 potential gas accumulation locations required by plant operating manual PLP-085, Emergency Core Cooling Systems Gas Management Program (GL 2008-01). Compliance with PLP-085 ensures the capability of the safety injection (SI), residual heat removal (RHR), and containment spray (CS) systems to perform their safety-related functions, and effectively implements the licensees gas management program as committed to the NRC in response to Generic Letter 2008-01. The licensee entered the issue into the corrective action program (CAP) as nuclear condition report (NCR) 575063, and is evaluating corrective actions. The failure to perform pre-RO UT examinations on 47 potential gas accumulation locations, as required by PLP-085 was a performance deficiency. The performance deficiency was more than minor because if left uncorrected, it had the potential to lead to a more significant safety concern. Specifically, if the licensee continued to miss pre-RO UT examinations, conditions that result in the formation of voids in the SI, RHR, and CS systems could go undetected with the potential to adversely affect the systems capability to perform their functions. The inspectors assessed the finding using IMC 0609 Attachment 4, Initial Characterization of Findings; and IMC 0609 Appendix A, The Significance Determination Process for Findings At-Power, and determined the finding was of very low safety significance (Green) because it was not a design deficiency, it did not represent the loss of a system safety function, did not result in exceeding a Technical Specification allowed outage time, and did not screen as potentially risk-significant due to a seismic, flooding, or severe weather initiating event. The inspectors identified a cross-cutting aspect in the work practices component of the human performance area, because the licensee did not define and effectively communicate expectations regarding procedural compliance and personnel following procedures. Specifically, on two occasions, the licensee did not perform pre-RO UTs in accordance with their gas management program, as described in PLP-085. |
| 05000335/FIN-2012005-01 | 2012Q4 | Saint Lucie | Failure to Follow Seismic Restraining Procedures on Ladders Located Near SAFETY-RELATED Equipment | An NRC identified non-cited violation (NCV) of Technical Specification 6.8.1, was identified which requires that written procedures be established, implemented, and maintained covering activities referenced in NRC Regulatory Guide 1.33, Revision 2, dated February 1978. The licensees procedures for seismic restraint of ladders: MA-AA- 100-1008, Station Housekeeping and Material Control; QI-13-PSL, Housekeeping and Cleanliness Controls Methods St. Lucie Plant; ADM-04.02, Industrial Safety Program; and ADM-27.11, Scaffold Control, were not implemented as written on ladders that were installed near safety-related equipment. The inspectors identified four examples of ladders not seismically restrained in accordance with the licensees procedures. During the licensees extent of condition review, 24 additional examples of ladders not in compliance with procedure requirements were identified. The licensees repeated failure to comply with procedures to seismically restrain ladders was a performance deficiency. Immediate corrective actions included completing a site-wide walk-down of the safety-related systems to identify and bring into procedural compliance any ladders that were not seismically restrained. The licensee entered this violation into the corrective action program as action request 1829233. The performance deficiency was determined to have more than minor significance because if left uncorrected, the failure to comply with station procedures to ensure adequate restraining of seismically controlled ladders, could lead to a more significant safety concern. Specifically, seismically unrestrained ladders could impact safety-related equipment during a design basis seismic event. The inspectors evaluated the risk of this finding using Manual Chapter 0609 Appendix A, Significance Determination Process for Findings At-Power, Exhibit 2- Mitigating Systems Screening questions. The inspectors determined that the finding was of very low safety significance because it did not require a quantitative assessment as determined in Exhibit 2. The finding involved the cross-cutting area of human performance, in the component of resources and the aspect of complete and accurate procedures (H.2.c) in that, the licensee failed to ensure complete, accurate, and up-to-date procedures were available for licensee personnel to ensure ladders were restrained to prevent seismic interaction with safety-related systems during a design basis seismic event. |
| 05000335/FIN-2012005-02 | 2012Q4 | Saint Lucie | Missing Relay Cover Results in Inadvertent Emergency Diesel Generator Actuation | A self-revealing, non-cited violation (NCV) of 10 CFR 50 Appendix B Criterion XVI Corrective Action was identified for failure to promptly identify and correct a missing cover on a safety-related under-voltage relay. The licensees failure to identify the missing relay cover on the 27X4 relay during the extent of condition review performed for condition report 406045 was a performance deficiency. Procedure PSL-01.05, Apparent Cause Evaluation (ACE) Handbook Section 7.6, dated July 30, 2008, provided the guidance for the required extent of condition review. The licensee added signage on the electrical cabinet door warning of the relay hazard, additional actions to determine the extent of condition and replace the relay cover is planned. The finding was determined to be more than minor because it affected the human performance attribute of the Initiating Events cornerstone and 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, without the relay cover installed, the relay was more vulnerable to actuation as a result of unintentional contact and a loss of the 1B3 vital 4 kV electrical bus occurred which required an unnecessary start and loading of the 1B EDG. The finding screened as Green because none of the attributes in the Manual Chapter 0609 Appendix G Attachment 1 Shutdown Operations Significance Determination Process Phase 1 Operational Checklist 3 were adversely impacted. The primary contributor to this conclusion was the licensees risk management controls which did not allow work in the train which was being relied upon for shutdown cooling. As a result, there was no loss of shutdown cooling for the event. There is no cross cutting aspect for the finding because the finding does not represent current licensee performance because the relay cover has been missing for several years. |
| 05000335/FIN-2012005-03 | 2012Q4 | Saint Lucie | Licensee-Identified Violation | St. Lucie Unit 1 Technical Specification 3.3.3.8, Accident Monitoring Instrumentation (with Table 3.3-11), requires, in part, that auxiliary feedwater flow instrumentation be operable in modes 1, 2, and 3. Action 7 of Table 3.3-11 requires inoperable auxiliary feedwater flow instrumentation to be returned to an operable condition within 72 hours or otherwise shutdown the unit to hot standby within six hours and to hot shutdown in 12 hours. Additionally, St. Lucie Unit 1 Technical Specification 6.8.1(a) states, in part, that the licensee shall establish, implement, and maintain the applicable procedures recommended in Appendix A of Regulatory Guide 1.33, Rev. 2, 1978. Section 9(a) of Appendix A to Regulatory Guide 1.33, Rev. 2, states, in part, that maintenance that can affect the quality 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 requirements, on May 10, 2012, the licensee did not implement adequate maintenance instructions that were appropriate to the circumstances in work order 40160852-01 to ensure that the safety-related square root extractor for auxiliary feedwater instrument FT-09-2A was wired correctly when it was installed in the plant and returned to service. As a result, FT-09-2A was inoperable from May 10, 2012, until discovery and correction of the wiring error on June 5, 2012 (27 days). The licensee entered this issue into their corrective action program as action requests 1773238 and 1828394. The failure to implement adequate work instructions in work order 40160852-01 to ensure that the square root extractor for FT-09-2A was wired correctly was a performance deficiency. The performance deficiency was more than minor because it was associated with the equipment performance attribute of the mitigating systems cornerstone and adversely impacted the cornerstone objective to ensure the availability, reliability, and capability of systems that respond to initiating events. The inspectors evaluated significance of the issue using NRC Inspection Manual Chapter 0609.04, Initial Characterization of Findings; and Inspection Manual Chapter 0609, Appendix A, The Significance Determination Process for Findings at Power, Exhibit 2. The inspectors determined the finding was of very low safety significance (Green) because the inoperable flow indication did not result in a loss of auxiliary feedwater heat removal safety function. Because this violation was of very low safety significance and was entered in the licensees corrective action program as action requests 1773238 and 1828394, this violation is being treated as a non-cited violation, consistent with Section 2.3.2 of the NRC Enforcement Policy. |
| 05000261/FIN-2012004-01 | 2012Q3 | Robinson | Failure to Include the Fuel Oil Supply to the Tsc/Eof/Security Diesel in the Maintenance Rule | The inspectors identified a Green non-cited violation (NCV) of 10 CFR 50.65(b)(2), Requirements for Monitoring the Effectiveness of Maintenance at Nuclear Power Plants, because the licensee failed to include all aspects of the Fuel Oil System in the maintenance rule program. Specifically, the fuel oil supply to the Technical Support Center (TSC) Emergency Operations Facility (EOF) Security Diesel is required to support the diesels emergency operating procedure (EOP) function of providing backup power to security lighting and the plant computer system. The licensee entered the issue into their corrective action program (CAP) as Nuclear Condition Report (NCR) 560424. The licensee corrective actions included revising the scoping document of the fuel oil system to include its function of providing fuel to the diesel. The failure to scope in the fuel oil system function of providing fuel to the TSC/EOF/Security Diesel to the maintenance rule program was a performance deficiency. The finding was more than minor because it impacted 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 scope in the fuel oil supply to the maintenance rule could affect the TSC/EOF/Security reliability and the accomplishment of EOPs. This finding was considered to have very low safety significance (Green) because the finding did not cause a loss of mitigation equipment functions and 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 more than 24 hours. This finding had a cross cutting aspect in the Corrective Action Program component of the Problem Identification and Resolution area, because the licensee failed to perform a thorough evaluation, such that the necessary support systems for the TSC/EOF/Security diesel were identified and added to the maintenance rule program. |
| 05000261/FIN-2012004-02 | 2012Q3 | Robinson | Licensee-Identified Violation | The following finding of very low significance was identified by the licensee and is a violation of NRC requirements, and, consistent with the NRC Enforcement Policy, is being dispositioned as an NCV. 10 CFR 50.63 Loss of All Alternating Current Power, requires in part that station batteries and other necessary support systems must provide sufficient capacity and capability to ensure the core is cooled and appropriate containment integrity is maintained in the event of a station blackout. Contrary to the above, on August 28, 2012 during PM-452, Dedicated Shutdown UPS Battery Test, the dedicated shutdown uninterruptible power supply (DS-UPS) batteries failed to meet the acceptance criteria. The licensee documented this condition in NCR 557582 and NCR 558425. The results of previous test indicated a negative trend in battery performance and that the battery should have been replaced before failure. The licensee initiated actions to replace the DS-UPS batteries. The inspectors evaluated this finding using NRC Inspection Manual Chapter 0609 Appendix F, Fire Protection Significance Determination. The finding was screened as having very low safety significance (Green) because the assigned fire degradation rating was low. In addition, based upon licensee procedures and operator actions, it is reasonable to conclude that the dedicated shutdown diesel generator would have been started and available to provide power to the required safe shutdown equipment prior to the battery falling below minimum voltage |
| 05000261/FIN-2012003-04 | 2012Q2 | Robinson | Inaccurate Safety System Functional Failure Performance Indicator Submittal | The inspectors identified a Severity Level (SL) IV NCV of 10 CFR 50.9(a), Completeness and Accuracy of Information, when the licensee inaccurately reported Safety System Functional Failure (SSFF) performance indicator data beginning with the 4th quarter of 2010. The licensee entered the issue into the CAP as NCR 539132. Corrective actions are still being evaluated. The inspectors determined the licensees failure to identify and document a SSFF was a performance deficiency. Specifically, Attachment 7 of REG-NGGC-009, NRC Performance Indicators and Monthly Operating Report Data, Rev. 11 requires documenting SSFFs for inclusion in the NRC performance indicator (PI) submittal. This resulted in a failure to submit complete and accurate PI data resulting from the investigation of LER 05000261/2011-001-00, Condition Prohibited by Technical Specifications When Non-Seismic System was Aligned to Refueling Water Storage Tank due to Regulatory Requirements . Due to the inadequate review of LER 05000261/2011-001-00, the licensee submitted inaccurate data for the SSFF PI beginning in the 4th quarter of 2010. If accurate data had been provided the SSFF PI would have transitioned from green to white in the 4th quarter of 2010. The finding was more than minor because it impacted the ability of the NRC to perform its regulatory oversight function. The finding was determined to be a SL IV violation using the examples in the Enforcement Policy, where a licensee submits inaccurate or incomplete PI data to the NRC that would have caused a PI to change from green to white. No cross-cutting aspect was assign due to traditional enforcement violations are not screened for cross-cutting aspects. |
| 05000261/FIN-2012003-02 | 2012Q2 | Robinson | Lack of Preventive Maintenance on Feedwater Control Switch Results in an Automatic Reactor Trip | A self-revealing Green finding was identified when the licensee failed to establish adequate preventative maintenance for equipment associated with the feedwater control systems. Specifically, the licensees inappropriate classification of the feedwater flow loop selector switch as a run-to-failure component permitted the switch to remain in service, without preventative maintenance, until its failure on March 28, 2012, which resulted in a feedwater transient and reactor trip. Corrective actions included the replacement of the failed switch and future replacement of seven additional switches that were deemed to be at risk for a similar failure. This issue has been entered into the corrective action program (CAP) as Nuclear Condition Report (NCR) #527203. The licensees inappropriate classification of plant equipment in accordance with ADMNGGC- 0107 Rev. 1, Equipment Reliability Process Guideline, which permitted feed flow selector switch 1/FM-488B to remain in service, without preventative maintenance, until failure was a performance deficiency. This finding was determined not to be a violation of NRC requirements. The finding was more than minor because it was associated with the initiating events cornerstone attribute of Equipment Performance, and it affected the associated cornerstone objective to limit the likelihood of those events that upset plant stability and challenge critical safety functions during shutdown as well as power operations. Specifically, the performance deficiency caused an automatic reactor trip from 55 percent power operations on March 28, 2012. The finding was determined to be of very low safety significance (Green) because the finding did not contribute to both the likelihood of a reactor trip and the likelihood that mitigating equipment or functions would not be available. The performance deficiency had a cross-cutting aspect of Evaluation of Identified Problems in the area of Problem Identification and Resolution, because the licensee failed to thoroughly evaluate the events in 2010 and 2008 such that the resolutions addressed the causes and extent of conditions as necessary. |
| 05000261/FIN-2012003-03 | 2012Q2 | Robinson | Inoperability of the Refueling Water Storage Tank Not Recognized as a Safety System Functional Failure | The inspectors identified a Green finding for the licensees failure to identify and document Safety System Functional Failures (SSFF) in accordance with REG-NGGC- 0009, NRC Performance Indicators and Monthly Operating Report Data. The licensee did not recognize that rendering the refueling water storage tank inoperable by placing the non-seismically qualified purification system in operation as documented in LER 05000261/2011-001-00, Condition Prohibited by Technical Specifications When Non- Seismic System was Aligned to Refueling Water Storage Tank due to Regulatory Requirements not Adequately Incorporated in Plant Documentation also created a SSFF. The licensee entered the issue into the CAP as NCR 539132. Corrective actions are still being evaluated. The inspectors determined that the licensees failure to identify and document a SSFF was a performance deficiency. Specifically, Attachment 7 of REG-NGGC-009, NRC Performance Indicators and Monthly Operating Report Data, Rev. 11 requires documenting SSFFs. The finding was determined to be more than minor because the minor screening question of whether the performance deficiency would have caused the SSFF PI to exceed a threshold was determined to have occurred. Specifically, had the licensee recognized the SSFFs and documented them during the investigation of LER 05000261/2001-001-00, the SSFF PI would have crossed the green/white threshold in the 4th quarter of 2010. The finding screened as Green because no loss of operability or functionality resulted from the failure to recognize the SSFF and document the event as described in LER 05000261/2011-001-00. The inspectors determined this performance deficiency had a cross-cutting aspect in the Corrective Action Program component of the Problem Identification and Resolution Area, because the licensee did not thoroughly evaluate the condition described in LER 05000261/2011-001-00, to include conditions such as a SSFF. |
| 05000261/FIN-2012003-01 | 2012Q2 | Robinson | Adequacy of PRE-PLANNED Mitigating Actions in Response to Declaring the Control Room Envelope Inoperable | An URI is being opened to provide for additional inspection in response to the actions performed by the licensee after declaring the control room envelope (CRE) inoperable due to not performing an adequate surveillance to demonstrate the integrity of the CRE. The inspectors noted on June 12, 2012, that in response to declaring the CRE inoperable on June 6, 2012, the licensee was required to verify mitigating actions to ensure CRE occupancy for design basis conditions in accordance with Technical Specification (TS) 3.7.9 Action G.2 was completed within 24 hours. Those actions are described in PLP-019, Control Room Envelope Habitability Program. An aspect of the mitigating actions included having self-contained breathing apparatus (SCBA) available for the control room occupants. The licensee verified five SCBAs were available in the control room for use by normal shift complement of licensed operators and shift technical advisor. The inspectors questioned whether the emergency communicator should have an SCBA. The licensee responded by adding a sixth SCBA on June 12, 2012. Additional inspection is required to determine if the emergency communicator is required to have an SCBA staged in the control room to support response to design basis conditions. |
| 05000261/FIN-2012002-01 | 2012Q1 | Robinson | Failure to Implement Technical Specification Action Requirements Regarding B Battery Inoperability | The inspectors identified a Green NCV of Technical Specification (TS) 3.8.4, DC Electrical Sources, when the licensee failed to comply with the action time following discovery of reasonable information to determine that Surveillance Requirement (SR) 3.8.4.6 had not been performed within its frequency plus 25 percent grace period for the B safety related battery. The B battery was inoperable due to the SR not being performed. The issue was documented in the corrective action program as Nuclear Condition Report (NCR) 511315. As corrective actions, the licensee shut down the plant and successfully performed the SR. The failure to declare in a timely manner that the TS surveillance requirement for the B safety related battery was not met, was a performance deficiency. This performance deficiency is more than minor because it is associated with the equipment performance attribute and adversely affected the Mitigating Systems Cornerstone objective to ensure the availability and reliability of systems that respond to initiating events to prevent undesirable consequences. Specifically, the licensee mistakenly extended the amount of time that they operated in Mode 1 with an inoperable safety related system. The significance of this finding was assessed in accordance with Inspection Manual Chapter 0609, Attachment 4. Using the Mitigating Systems Cornerstone column of Table 4a of Attachment 4, it was determined that the finding was of very low significance (Green) because the finding did not represent a loss of safety function and did not screen as potentially risk significant due to a seismic, flooding or severe weather initiating event. The inspectors determined this performance deficiency has a cross-cutting aspect in the Decision Making component of the Human Performance Area, because the licensee did not use conservative assumptions to determine operability of the B safety related battery. |
| 05000261/FIN-2012002-02 | 2012Q1 | Robinson | Inadequate Design Change Resulted in Interference and Inoperability of Containment Water Level Indication | The inspectors identified a Green NCV of 10 CFR 50, Appendix B, Criterion III, Design Control, for the licensees installation of a plant modification that adversely affected the operability of nearby safety related equipment. Specifically, the licensees installation of radiation barriers in containment impeded the travel path for equipment associated with containment water level transmitter, LT-802E, and resulted in the B train of containment sump water level instrumentation being inoperable for a period of time greater than allowed in Technical Specification 3.3.3. The licensee took immediate actions to remove the interference with the level instrumentation. This issue was entered into the licensees corrective action program as NCR 510240. The licensees installation of a plant modification that adversely affects the operability of nearby safety related equipment was a performance deficiency and resulted in containment water level transmitter, LT-802E, being inoperable for greater than the allowed outage time specified in Technical Specification 3.3.3. The performance deficiency was considered more than minor because it affected the Mitigating Systems Cornerstone objective of ensuring the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences (i.e. core damage). Specifically, reactor operators would have unreliable indication of containment water level during a postulated Loss of Coolant Accident (LOCA). Using Manual Chapter 0609.04, Phase 1 Initial Screening and Characterization of Findings, the issue was evaluated to be a degradation of the Mitigation Systems cornerstone because it affects long term core decay heat removal in the event of a LOCA. Table 4a of the Phase 1 worksheet requires a Phase 2 significance determination evaluation, because the finding represents an actual loss of safety function of a single train, for greater than its Technical Specifications Allowed Outage Time. A further characterization of the safety significance could not be performed in Phase 2 because the function (i.e., containment water level indication) was not modeled and necessitated that a Phase 3 SDP be done. The SRA performed a bounding event assessment. The dominant accident sequence was where a LOCA occurs and, as a result of the depressurization, a Steam Generator Tube Rupture happens. This leads to the water from the steam generator adding to the internal flooding event. Subsequently operators fail to isolate the ruptured steam generator thus continuing to feed the break. The increase in core damage probability (ACDF) for this event was determined to be < 1E-6 therefore, this condition should be treated as very low safety significance (Green). The inspectors did not identify a crosscutting aspect associated with this finding because the performance deficiency occurred in 2005 and does not represent current licensee performance. |
| 05000261/FIN-2012002-03 | 2012Q1 | Robinson | LOW Temperature Overpressure System Rendered Inoperable for Operational Convenience | The inspectors identified a Green finding for failure to follow the TS bases associated with Improved Technical Specification (ITS) 3.0.2 Limiting Condition for Operability (LCO) Applicability. Specifically, the licensee rendered the Low Temperature Overpressure Protection System (LTOP) inoperable and entered ITS 3.4.12 Condition G for operational convenience. On March 11, 2012, for approximately 90 minutes, while transitioning the Low Temperature Overpressure System from ITS LCO 3.4.12 b. to ITS LCO 3.4.12 a., the LTOP system was rendered inoperable. This issue has been entered in the corrective action program as NCR 523648. Corrective actions are being evaluated. Rendering the LTOP system inoperable for operational convenience was a performance deficiency. The finding was more than minor because it impacted the Equipment Performance attribute of the Barrier Integrity Cornerstone, and adversely affected the cornerstone objective to provide reasonable assurance that the physical design barriers of the reactor coolant system protect the public from radionuclide releases caused by accidents or events. Specifically, with an inoperable LTOP system the RCS protection from an overpressure event is reduced. The significance of this finding was assessed using Inspection Manual Chapter 0609 Shutdown Significance Determination Process Appendix G. The inspectors determined that the finding was of very low safety significance (Green) and it did not adversely impact the five guidelines contained in Checklist 4 of core heat removal, inventory control, power availability, containment closure, or reactivity. No cross-cutting aspect is associated with this finding as the performance deficiency does not reflect current licensee performance in that licensee has utilized this process for years. |
| 05000321/FIN-2011005-01 | 2011Q4 | Hatch | Failure to identify all the applicable reporting codes when submitting an LER | An NRC-identified Severity Level IV non-cited violation of 10 CFR 50.9, Completeness and Accuracy of Information, was identified when the licensee failed to include all applicable reporting codes on licensee event report (LER) 2- 2011-001, Primary Containment Isolation Penetration Exceeded Overall Allowable Technical Specification Leakage Limits. Specifically, the circumstances identified in LER 2-2011-001 met the conditions to be reported under 10 CFR 50.73(a)(2)(v)(C), a condition which could have prevented the fulfillment of the safety function of systems that are needed to control the release of radioactive material, but was not. The licensee issued a revision to LER 2-2011-001 to correct this violation. This violation was entered into the licensees corrective action program as CR 371298. Failure to identify all the applicable reporting codes when submitting an LER to the Commission is a performance deficiency. Because this violation was determined to have the potential for impacting the NRCs ability to perform its regulatory function, it was evaluated using the traditional enforcement process. The inspectors reviewed the NRC Enforcement Policy and determined this finding was a Severity IV violation based on example 6.9.d.10., which states, A failure to identify all applicable reporting codes on a Licensee Event Report that may impact the completeness or accuracy of other information (e.g., performance indicator data) submitted to the NRC. No cross-cutting aspect was assigned, because traditional enforcement violations are not screened for cross-cutting aspects. |
| 05000348/FIN-2011014-01 | 2011Q4 | Farley | TDAFW Pump Inoperable due to Improper Control of Station Drawings | A self-revealing non-cited violation (NCV) of 10 CFR 50, Appendix B, Criterion III, Design Control was identified for the licensee s failure to correctly update their design drawing for the Unit 2 Turbine Driven Auxiliary Feedwater (TDAFW) pump electrical controls. This drawing was later used to correct existing discrepancies (a condition adverse to quality) with the TDAFW pump electrical controls which resulted in the Unit 2 TDAFW pump being inoperable. This condition revealed itself 24 days later when the licensee performed a surveillance test to confirm operability of the TDAFW pump from the Hot Shutdown Panel and the pump tripped on an overspeed condition. The licensee restored operability of the TDAFW pump on July 31, 2011, by re-landing the lifted electrical leads. Failure to maintain the accuracy of station controlled design drawings is a performance deficiency. This performance deficiency is more than minor because it is associated with the Design Control attribute of the Mitigating Systems cornerstone objective of ensuring the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences (i.e., core damage). Specifically, the licensee did not maintain adequate design control of the TDAFW pump electrical control drawings which were relied upon to maintain proper configuration of the plant. The inaccurate drawings resulted in the Unit 2 TDAFW pump being inoperable for approximately 24 days. The finding was evaluated using the work sheets of MC 0609, Significance Determination Process, Attachment 4, and Appendix A. The inspectors determined further review was required by the regional senior risk analyst (SRA) to determine significance. The regional SRAs used the latest NRC Farley Standardized Plant Analysis Risk (SPAR) model and the licensee s full scope Farley Probabilistic Risk Assessment (PRA) model. The licensee s Farley Fire PRA model was used to estimate the external event fire risk. Recovery human error probabilities were developed using the NRC SPAR-H methodology for diagnostic and action portions of the recovery. The major assumptions of the analysis included: (1) The TDAFW pump would start and trip on overspeed for all automatic and remote manual start attempts, (2) An exposure period of 593 hours, and (3) TDAFW pump recovery via local manual trip and throttle valve control for all scenarios except Anticipated Transient Without Scram and Loss of Seal Cooling scenarios due to time constraints. The dominant sequences were (1) a Loss of Service Water initiator due to pipe rupture leading to a loss of Component Cooling Water and the motor driven AFW pumps, loss of the TDAFW due to the PD, and failure to recover the TDAFW pump via local manual control leading to RCP seal LOCA and core damage, and (2) a Reactor Trip initiator with a common cause failure of the motor driven AFW pumps, loss of the TDAFW pump due to the PD, failure to recover the TDAFW pump via local manual control and failure to implement feed and bleed leading to core damage. The risk was mitigated by the remaining AFW capability, the fact that the PD only affected the TDAFW pump and did not prevent recovery via local manual control, and the relatively short exposure period. The core damage frequency increase was less than 1X10-6 per year; therefore the finding was of very low risk significance (GREEN). The inspectors identified a cross-cutting aspect in the Work Control component of the Human Performance cross-cutting area (H.3(b)). Specifically, the licensee failed to coordinate between departments during planning activities in which interdepartmental coordination was necessary to assure plant performance. |
| 05000321/FIN-2011005-02 | 2011Q4 | Hatch | Cables for Fire Safe Shutdown Not Protected In Accordance With 10 CFR 50 Appendix R Section III.G.2 | The NRC identified a Green non-cited violation (NCV) of 10 CFR Part 50, Appendix R, Section III.G.2, for the licensees failure to protect one of the redundant trains of cables, located in the same fire area (FA), needed to achieve post-fire safe shutdown (SSD) from fire damage for multiple fire areas for Unit 1. Upon discovery, the licensee entered this item into their corrective action program as Condition Report (CR) 100755. As corrective actions, the licensee had implemented modifications to eliminate the need for local operator manual actions (OMAs) to achieve SSD. However, the inspectors discovered that, for FZ 0014K, the modifications did not adequately eliminate reliance on local OMAs to achieve SSD. The licensee entered this condition into the corrective action program as CR 364483. At the time of the exit meeting, the licensee planned to reroute affected cables out of the affected FA. The licensees failure to protect one train of cables and equipment necessary to achieve post-fire SSD from fire damage for fire areas designated in the fire protection program as meeting 10 CFR 50 Appendix R, Section III.G.2, is a performance deficiency. This finding is more than minor because it is associated with the reactor safety mitigating system cornerstone attribute of protection against external events (i.e., fire). Failure to protect safe shutdown cables and equipment from fire damage affects the reactor safety mitigating systems cornerstone objective of ensuring the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences. The inspectors used NRC Inspection Manual Chapter 0609, Appendix F, Fire Protection Significance Determination Process, and determined the finding was of very low safety significance (Green). Inspectors determined that no cross cutting aspect was applicable to this performance deficiency because this finding was not indicative of current licensee performance. |
| 05000321/FIN-2011005-03 | 2011Q4 | Hatch | Licensee-Identified Violation | On July 5, 2011, a licensee-identified violation of Unit 2 TS 3.4.3 was discovered. TS section 3.4.3 requires 10 of 11 safety relief valves (SRVs) to be operable during Mode 1, 2, and 3. Contrary to this requirement it was identified during bench testing that eight safety relief valves failed to lift at the required technical specification setpoint, and therefore where inoperable when Unit 2 was in Mode 1, 2, and 3. The cause for the SRVs failing to lift within the required setpoint was due to corrosion induced bonding between the pilot disc and seating surface. This condition was documented in CR 334250. Analysis showed that with the SRVs lifting at the as-found bench test setpoints the SRVs still would have maintained reactor coolant system pressure below the TS safety limit requirements. Therefore, this finding was determined to be of very low safety significance |
| 05000424/FIN-2011005-01 | 2011Q4 | Vogtle | Human Performance Error Results in Inoperability of TDAFW Pump | A Green self-revealing non-cited violation (NCV) of 10 CFR 50, Appendix B, Criterion V, Instructions, Procedures, and Drawings, was identified. Specifically, the licensee inadvertently operated the Unit 2 turbine driven auxiliary feedwater (TDAFW) pump with the suction source isolated. As a result, the TDAFW pump operated with no suction source for a period of 1 minute 20 seconds and was rendered inoperable for a period of approximately 22 hours. The licensee immediately secured the pump when suction and discharge pressures became erratic and unstable. The licensee performed an engineering evaluation and assessment to ensure the pump was not damaged as a result of running the pump with the suction valves closed. The licensee entered this issue into their corrective action program (CAP) as CR 358773. This issue was more than minor because it adversely affected an objective of the Mitigating Systems cornerstone. Specifically, the performance deficiency affected the availability, reliability, and capability of the Unit 2 TDAFW pump to provide secondary decay heat removal. The finding was determined to be Green because the event did not represent an actual loss of safety function of a single train for greater than its technical specification (TS) allowed outage time. The inspectors determined that the cause of this finding was related to the Work Practices component of the Human Performance crosscutting area due to less-than-adequate human error prevention techniques (H.4(a)). Specifically, procedural place keeping techniques were less than adequate. |
| 05000424/FIN-2011005-02 | 2011Q4 | Vogtle | Failure to ensure Unit 1 and Unit 2 reactor coolant process variables can be maintained within those predicted for a loss of normal ac power for a large main control room fire\\\" | A Green NRC identified NCV of Unit 1 Operating License Condition 2.G and Unit 2 Operating License Condition 2.G for failure to implement and maintain in effect all provisions of the approved Fire Protection Program (FPP) as described in the FSAR for the facility. Specifically, the licensee failed to ensure that, during post-fire safe shutdown, Unit 1 and Unit 2 reactor coolant process variables would be maintained within those predicted for a loss of normal ac power. The licensee entered this issue into their corrective action program (CAP) as Condition Report (CR) 2010112114. The finding was determined to be more than minor because it was associated with the Reactor Safety Mitigating Systems cornerstone attribute of protection against external factors (i.e. fire) and it affected the cornerstone objective of ensuring the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences. The inspectors determined that this performance deficiency did not have a cross-cutting aspect because it did not represent current licensee performance. |
| 05000424/FIN-2011005-03 | 2011Q4 | Vogtle | Licensee-Identified Violation | Technical Specification (TS) 3.0.4, Limiting Condition for Operation (LCO) Applicability states in-part, When an LCO is not met, entry into a Mode or other specified condition in the Applicability shall only be made; a) When the associated ACTIONS to be entered permit continued operation in the Mode or other specified condition in the Applicability for an unlimited period of time; or b) After performance of a risk assessment addressing inoperable systems and components or c) When an allowance is stated in the individual value, parameter or other Specification. Contrary to this requirement on October 27, 2011 it was discovered by the licensee that Mode changes had been made contrary to TS LCO 3.0.4. Technical Specification (TS) 3.3.4, Remote Shutdown System, Limiting Condition for Operation (LCO) is applicable in Modes 1, 2, and 3 and requires two channels of Core Exit Thermocouples (CETC) to be operable. During startup from the refueling outage 2R15, one of the CETC channels credited for satisfying this requirement was inoperable but was not recognized as being inoperable until the unit was in Mode 1. Since mode changes were made with only one of the two required CETC channels operable, the unit was operated in a condition contrary to TS LCO 3.0.4. The inspectors used Inspection Manual Chapter 601, Phase 1 worksheets, mitigating systems cornerstone, to conduct an initial screening and characterization of this violation. The inspectors concluded, from this screening, that this violation was of very low significance (Green). The licensee has entered this issue into their corrective action program as CR 374623, completed an enhanced apparent cause determination, drafted LER 05000425/2011-001, and implemented a temporary modification to restore the channel to operable status. This licensee-identified violation is closed. |
| 05000348/FIN-2011004-01 | 2011Q3 | Farley | Failure to properly pre-plan maintenance activities while conducting tagout operations on the 2C charging pump | A self-revealing NCV of Technical Specification (TS) 5.4.1a was identified for the licensees failure to implement procedures recommended in Regulatory Guide (RG) 1.33. Specifically, the licensee did not properly pre-plan maintenance tagout activities on the unit 2 charging system. As a result, the licensee inadvertently overpressurized the 2C high head safety injection (HHSI) pump suction piping, adversely affecting the availability of the safety-related pump. Upon discovery of this condition, the licensee immediately depressurized the pump suction piping and initiated condition report (CR) 343336. Failure to properly pre-plan maintenance activities is a performance deficiency. This performance deficiency is more than minor because it is associated with the human performance attribute of the mitigating systems (MS) cornerstone, and adversely affected the cornerstone objective to ensure system availability of components responding to initiating events preventing undesirable consequences. The human performance attribute of the MS cornerstone was determined to be adversely affected because: 1) the licensees tagout procedure relied on a check valve as part of the maintenance boundary; 2) the licensees tagout sequence isolated the pump suction valve prior to isolating the pump discharge valve; resulting in overpressurization of the 2C charging pump suction piping, which rendered the 2C charging pump inoperable from August 11, 2011, to September 9, 2011. The significance of this finding was screened using IMC 0609, Significance Determination Process (SDP), Phase 1 worksheets of Attachment 4. The finding screened as Green, because it did not represent an actual loss of safety function of a single train of emergency core cooling system (ECCS) for greater than its TS allowable outage time. The finding was assigned a cross cutting aspect in the resources component of the human performance area (H.2(c)). Specifically, complete, accurate and up-todate work packages could have prevented overpressurization of the pump. |
| 05000261/FIN-2011004-01 | 2011Q3 | Robinson | Water Intrusion into Safety-Related Buildings due to Inadequate Design of Site Storm Water Runoff Drainage System | A self-revealing apparent violation (AV) of 10 CFR 50, Appendix B, Criterion III, Design Control, was identified for the licenseei12s failure to consider how the aggregate changes to the sitei12s topography could impact the sitei12s ability to drain storm water runoff and adequately respond to localized flooding during periods of heavy rain. This resulted in the ponding of storm water runoff, the subsequent direction of runoff flow towards the power block, overfilling of the retention basin, backup of the storm drainage system, and ultimately, uncontrolled water intrusion into safety-related equipment rooms in the auxiliary building. The licensee took immediate actions to remove the water from the affected plant buildings and grounds. In addition, within a few weeks of the event, the licensee repaired the washed out area of the berm just to the north of the power block, and performed interim adjustments to site topography to limit ponding near the berm. The licensee plans to perform additional site grade and trench restoration and remediation to permanently prevent site ponding. This issue was entered into the licensee\\\'s corrective action program as NCR 468235. The licensee\\\'s failure to consider how the aggregate changes to the site\\\'s topography could impact the site\\\'s ability to drain storm water runoff and adequately respond to localized flooding during periods of heavy rain as required by procedure EGR-NGGC- 0005, Engineering Change, was a performance deficiency. This performance deficiency was considered more than minor because it was associated with the Initiating Events Cornerstone attributes of the Design Control (plant modifications) and Protection Against External Factors (flood hazard), and adversely affected the cornerstone objective to limit the likelihood of those events that upset plant stability and challenge critical safety functions during shutdown as well as power operations. Specifically, the failure to consider aggregate changes to the site\\\'s topography on the site\\\'s ability to drain storm water runoff resulted in uncontrolled water intrusion into safety-related equipment rooms. The inspectors assessed the finding using Inspection Manual Chapter (IMC) 0609, Significance Determination Process (SDP), Att. 4, Phase 1 - Initial Screening and Characterization of Findings, and determined the finding was potentially greater than very low safety significance because the finding increases the likelihood of an external flooding event. As a result, the characterization worksheet for Initiating Events required a Phase 3 analysis using the Individual Plant Examination for External Event Submittal (IPEEE) or other existing plant specific analyses as inputs. The significance of this finding is designated as To Be Determined (TBD) until the safety characterization has been completed by the NRC Senior Reactor Analyst (SRA). The inspectors determined that the cause of this finding was related to the trending and assessment aspect in the Corrective Action Program component of the Problem Identification and Resolution cross-cutting area. |
| 05000261/FIN-2011004-02 | 2011Q3 | Robinson | Failure to Take Prompt Corrective Actions to Establish Guidance to Monitor and Operate Service Water Strainers Following LOOP | The inspectors identified a Green NCV of Technical Specification (TS) 5.4.1, Administrative Controls, Procedures, for failure to establish procedural guidance to monitor Service Water System (SWS) parameters and operate the SWS strainers following a loss of offsite power (LOOP). Following a LOOP, the operator's ability to recover from a plugged SWS strainer would be impacted due to the loss of the associated control alarm and the lack of procedural guidance to manually operate the SWS strainers. The licensee has revised plant procedures to include additional instructions that will ensure that operators can recover from plugged SWS strainers and preserve the operation of the SWS following a LOOP. This issue was entered into the licensee's corrective action program as NCR 473900. The failure to establish procedural guidance to locally monitor SWS parameters and manually operate the SWS strainers following a LOOP was a performance deficiency. This issue was more than minor because if left uncorrected this finding would have the potential to lead to a more significant safety concern. Specifically, the inability to clean the service water strainers, following a prolonged LOOP, could impact the operation of the service water system. The SDP Phase 1 screening determined that this finding was within the mitigating systems cornerstone and was potentially risk significant due to a seismic, flooding or severe weather initiating event and therefore required a Phase 3 SDP analysis. An NRC Senior Reactor Analyst (SRA) determined the lack of procedure for a loss of the service water strainers due to an external event (i.e., loss of offsite power removing power to the strainers and causing debris to clog the system) was of very low risk significance i.e., Green. The main contributors to the low risk results were: 1) the low likelihood of a total loss of service water event, and 2) the probability of recovery of the strainers and/or the system despite the lack of procedures. The inspectors determined that the finding has a cross-cutting aspect in the Corrective Action Program component of the Problem Identification and Resolution area, because the licensee failed to thoroughly evaluate the issue such that the resolution addressed the cause and extent of conditions, as necessary. Specifically, licensee's evaluation of the NCR associated with the lack of plant procedures to manually operate the SWS, failed to recognize that the control room indication associated with a plugged SWS strainer would be lost following a LOOP. |
| 05000424/FIN-2011004-01 | 2011Q3 | Vogtle | Installation of Non-Conforming Safety-Related Breakers due to a Failure to Implement Corrective Action To Prevent Recurrence to Address a Significant Condition Adverse to Quality | An NRC-identified Green NCV of 10 CFR Part 50, Appendix B, Criterion XVI, Corrective Action, was identified for failure to develop and implement adequate corrective action to prevent recurrence (CAPR) in response to a significant condition adverse to quality (SCAQ) associated with E-MAX safety-related breaker front cover mounting screws. The licensee performed a field walk-down of all installed E-MAX breakers and identified a total of six breakers that had been inadvertently installed with the top right-hand front cover plate screw not removed. The licensee immediately removed the suspect screws and implemented corrective actions to address future EMAX breaker installations. The licensee entered this issue into their corrective action program (CAP) as CR 332562. The finding was considered more than minor because it impacted the Reactor Safety Mitigating Systems Cornerstone objective to ensure the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences and affected the cornerstone attribute of equipment performance. Specifically, the inadequate corrective action allowed for the installation of nonconforming safety-related breakers that incurred unplanned unavailability to implement the associated temporary modification and also decreased reliability during the time the breaker was in-service without the temporary modification installed. The inspectors determined that the cause of this finding was related to the Corrective Action Program component of the Problem Identification and Resolution cross-cutting area due to the licensees failure to take appropriate corrective actions to address safety issues in a timely manner, commensurate with their safety significance and complexity (P.1(d)). (Section 4OA2.2) |
| 05000424/FIN-2011004-02 | 2011Q3 | Vogtle | Loss of Both Trains of Control Room Emergency Filtration System (CREFS) Actuation Instrumentation | Technical Specification (TS) 3.3.7, Limiting Condition for Operation (LCO) Applicability, LCO 3.3.7 Condition P, requires that when four intake radiological gas monitor channels are inoperable, operators must place one CREFS train in each unit in the emergency mode within 1 hour. Contrary to the above, on September 22, 2011, the licensee discovered that AHV12153 was closed. This condition prevented air flow past all four radiological gas monitors rendering them inoperable. A review of the plant computer system showed that the valve was closed on September 19, at 2015. Thus for a period of approximately two and half days, Unit 1 & 2 were operated in a condition prohibited by TS 3.3.7, which is applicable in Modes 1, 2, 3 and 4. This finding is not greater than green using the IMC 609 Phase 1 worksheet due to the finding only representing a degradation of the radiological barrier function provided for the control room. The licensee has entered this issue into their corrective action program as CR 353533, completed a basic cause determination, drafted LER 05000424,425/2011-003, and immediately restored the valve to its proper position |
| 05000261/FIN-2011003-02 | 2011Q2 | Robinson | Inadequate Seismic Analysis for Installation of Safety Related Cable Trays and Conduit | The inspectors identified a Non-Cited Violation (NCV) of 10 CFR Part 50, Appendix B, Criterion III, Design Control, for the licensees failure to perform an adequate seismic analysis during the plant modification of the 125VDC Battery Chargers. Specifically, the interface evaluation for installation of the safety-related, Battery Charger, cable tray and conduit failed to consider the seismic interaction with the adjacent air-handling unit structure. Subsequent review and analysis determined that the modification introduced a degraded/nonconforming condition which does not affect operability. The licensee documented the issue in Nuclear Condition Report 458971 and initiated actions for a plant modification. The failure to perform an adequate seismic analysis for the installation of the safetyrelated cable trays and conduit is a performance deficiency. This performance deficiency is associated with the design control attribute of the Mitigating System Cornerstone. It is more than minor since it is similar to Inspection Manual Chapter 0612, Appendix E, Example, 3.a, in that the seismic analysis for the cable trays and conduits require revision and modification to the air handling unit structural supports to correctly resolve the seismic concerns. In accordance with IMC 0609 (Table 4a), Phase 1 Initial Screening and Characterization of Findings, the finding was determined to be of very low safety significance (Green) because the finding was not a design or qualification deficiency which resulted in a loss of operability or functionality. The inspectors did not identify a cross-cutting aspect associated with this finding because the performance deficiency occurred in 1991 and does not represent current licensee performance. |
| 05000261/FIN-2011003-03 | 2011Q2 | Robinson | Refueling Water Storage Tank Inoperable While On Purification | The inspectors identified a NCV of Technical Specification (TS) 3.5.4 Refueling Water Storage Tank (RWST), which required the RWST to be operable in modes 1 through 4. The licensee failed to comply with the TS Action Statements when the RWST was rendered inoperable by placing the non-seismically qualified purification loop in operation. Upon discovery the licensee promptly restored the RWST to operable status by removing the purification loop from service, put administrative controls in place to prevent use of the purification loop, and initiated Action Request (AR) 452093 to evaluate the event. Use of the non-seismically qualified Spent Fuel Pool Demineralizer System for purification of the Refueling Water Storage Tank was determined to be a performance deficiency. This action rendered the RWST inoperable and the licensee failed to comply with the required action statement for an inoperable RWST. The finding is more than minor because if left uncorrected, the performance deficiency has the potential to lead to a more significant safety concern. Specifically, during a seismic event the purification piping could break and cause a loss of inventory in the RWST. Significance Determination Process (SDP) Phase 1 screening determined that this finding was within the mitigating systems cornerstone and was potentially risk significant due to a seismic external event and therefore required a Phase 3 SDP analysis. A phase 3 risk assessment was performed by a regional SRA using the NRC SPAR model. An exposure period of 213 days was utilized as this represented the worst case one year exposure period determined using the RWST purification history data. No recovery credit was assumed in the analysis. The non-seismic RWST purification piping and the dedicated shutdown diesel generator were assumed to fail at the same seismic input as that assumed for a loss of offsite power. The dominant sequence was a seismically induced loss of offsite power leading to a station blackout with failure of the emergency power system and failure to recover offsite power or the emergency diesel generators. Subsequent battery depletion and operator failure to control the turbine driven auxiliary feedwater pump would lead to core damage. The risk was mitigated by the low probability of a seismic event and the failure probability of the emergency diesel generators. The analysis determined that the risk increase of the performance deficiency was an increase in core damage frequency less than 1E-6/year a GREEN finding of very low safety significance. The cause of the finding was directly related to the conservative assumptions aspect in the Decision Making component of the Human Performance area because during a previous review of this evolution the licensee did not demonstrate the proposed action was safe in order to proceed. Instead the licensee could not find a requirement to show it was unsafe and concluded placing the RWST on purification was acceptable. |
| 05000261/FIN-2011010-01 | 2011Q2 | Robinson | Simultaneous Closure of Several Engineering Change Requests Not Meeting Administrative Requirements | The inspectors noted that NCR 417814 was written to address a condition adverse to quality associated with the cancellation of approximately 375 ECRs which were cancelled without technical justification. The NCR stated that the individual ECRs were cancelled as part of a corrective action associated with an earlier NCR (382451) which identified the ECRs as not meeting an administrative requirement to have a management sponsor. Inspectors noted that the corrective actions taken by the licensee did not ensure that each cancelled ECR was reviewed to ensure the existence of an adequate technical basis for cancellation. Inspectors also noted that the evaluation did not consider that some of the ECRs were intended to correct previously identified conditions adverse to quality as documented in NCRs. The inspectors identified that at least one open NCR corrective action was inappropriately closed due to the cancellation of the ECRs. Inspectors concluded that further review of information related to the closure of the ECRs and any related NCRs is necessary to determine if the issue is more than minor. The licensee entered this issue into their corrective action program as NCR 417814. This issue is identified as URI 0500261/2011010-01, Simultaneous Closure of Several Engineering Change Requests Not Meeting Administrative Requirements. |
| 05000261/FIN-2011003-01 | 2011Q2 | Robinson | Rainstorm Results in Flooding of the Power Block | On May 27, 2011, a heavy rainstorm was not successfully managed by the sites engineered rainwater management features. This resulted in water run-off into the protected area, backing up of storm drains and water intrusion into the power block, Auxiliary Building and other support buildings. Additional review by the NRC is required following the completion of the licensee\\\'s root cause investigation. The review will determine whether this issue represents a performance deficiency. This issue is identified as URI 05000261/2011003-1, Rainstorm Results in Flooding of the Power Block. |
| 05000261/FIN-2011002-02 | 2011Q1 | Robinson | Failure to Update the Updated Final Safety Analysis Report Contributed to Insufficient Emergency Diesel Generator Lube Oil Inventory | The inspectors identified a Severity Level IV (SL-IV) non-cited violation (NCV) for failure to update the Updated Final Safety Analysis Report (UFSAR), as required by 10 CFR 50.71(e), to include the minimum required inventory of lube oil for operation of the emergency diesel generators, following the conversion to improved standard technical specifications (ISTS). The inspectors determined that the failure to include this information contributed to the licensee falling below the minimum lube oil inventory required for the Emergency Diesel Generators to meet their seven day mission time. The licensee took immediate corrective actions to obtain sufficient lube oil and entered the issue into the corrective action program as nuclear condition report (NCR) 452251. This issue was considered as traditional enforcement because it had the potential for impacting the NRCs ability to perform its regulatory function. This issue is more than minor because not having an updated portion of the UFSAR hinders the licensees ability to perform adequate 10 CFR 50.59 evaluations and can impact the NRCs ability to perform adequate regulatory reviews for license amendments and inspections. Consequently, it can have a material impact on licensed activities. This issue was determined to meet the criteria for a severity level IV violation in the NRC Enforcement Policy because the information was not used to make an unacceptable change to the facility or procedures. No cross-cutting aspect was assigned because cross-cutting aspects are not assigned to violations being dispositioned through the traditional enforcement process |
| 05000261/FIN-2011002-03 | 2011Q1 | Robinson | Inadequate 10 CFR 50.59 evaluation results in Emergency Core Cooling System Inoperability | The inspectors identified a Severity Level IV (SL-IV) non-cited violation (NCV) of 10 CFR 50.59 for the licensees failure to perform an adequate safety evaluation documenting why implementing a procedure change for the Emergency Core Cooling System (ECCS) Residual Heat Removal (RHR) injection sub-system did not present a more than minimal increase in the likelihood of occurrence of a malfunction of a structure, system, or component (SSC) important to safety previously evaluated in the updated safety analysis report (UFSAR). The licensee erroneously referenced a vendor analysis which was not part of the licensing basis to support the safety evaluation. The procedure change was used by Operations and resulted in a violation of Technical Specification (TS) 3.5.3 ECCS Shutdown for the required RHR injection sub-train being inoperable in Mode 4 and the associated action statement was not complied with. After the fact and upon discovery, the licensee established administrative controls to ensure compliance with TS in the future. The issue was entered into the corrective action program as NCR 425136. The licensees use of an unapproved vendor evaluation of LOCA response as justification to support a 10 CFR 50.59 safety evaluation was a performance deficiency. The traditional enforcement review of the performance deficiency is more than minor because plant procedures were changed without prior NRC review and approval, which impacted the regulatory process. Violations of 10 CFR 50.59 are dispositioned using the Traditional Enforcement process instead of the SDP because they are considered to be violations that could potentially impede or impact the regulatory process. However, if possible, the underlying technical issue is evaluated under the SDP to determine the severity of the violation. In this case, the inspectors determined the finding could be evaluated under the SDP because the ECCS RHR injection subsystem became inoperable because of an inadequate safety evaluation and procedure change resulting in a violation of TS 3.5.3, ECCS-Shutdown. The finding was evaluated using IMC 0609.04, Significance Determination Process (SDP) Phase 1 screening worksheets. This finding adversely impacted the Mitigating Systems cornerstone objective to ensure the availability of systems that respond to initiating events to prevent undesirable consequences. Because it represented an actual loss of safety function of both trains of RHR, an SDP Phase 2 analysis was required. The inspectors determined that the finding could not be adequately assessed using the Phase 2 process; therefore, a SDP Phase 3 analysis was performed for the deficiency using an at-power (vice a shutdown evaluation) because the performance deficiency would manifest itself immediately after shutting down the unit or immediately preceding returning to power. The NRC\'s risk model was modified to reflect the total loss of RHR injection capability due to either voiding of the pump suctions or the associated waterhammer event. The resulting analysis, including the risk contribution due to external sources, was less than 1E-6/year and the finding is Green. The dominant cutsets were medium and small break loss of coolant accidents that proceed immediately to core damage due to the lack of low pressure injection. In accordance with Section 6.1.d.2 of the NRC Enforcement Policy, this violation is categorized as Severity Level IV because the resulting changes were evaluated by the SDP as having very low safety significance (Green). The inspectors determined the cause of the finding was directly related to verification of underlying assumptions aspect in the decision making component of the Human Performance area because the licensee did not validate whether the vendor analysis was part of the licensees licensing basis (H.1(b)) |
| 05000261/FIN-2011002-01 | 2011Q1 | Robinson | Two of Six Operating Crew Failures on the Simulator Operational Evaluation Portion of the 2011 Annual Requalification Operating Test | A self-revealing Green finding associated with operating crew performance on the simulator during facility-administered requalification examination was identified. Two of the six crews evaluated failed to pass their simulator examinations. As immediate corrective action, the failed operating crews were remediated (i.e., the operating crews were re-trained and successfully retested) prior to returning to shift. The licensee has entered this issue into the corrective action program as non-conformance report (NCR) 444843. The inspectors determined that the crew failures constituted a performance deficiency based on the fact that licensed operators are expected to operate the plant with acceptable standards of knowledge and abilities demonstrated through periodic testing as required by 10 CFR 55.59(a)(2). Two out of six crews of licensed operators failed to demonstrate a satisfactory understanding of the required actions and mitigating strategies required to safely operate the facility under normal, abnormal, and emergency conditions. The finding is more than minor because the performance deficiency potentially affects the Human Performance attribute of the Mitigating Systems cornerstone objective to ensure the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences. Specifically, the finding reflected the potential inability of the crew to take appropriate safety-related action in response to actual abnormal and emergency conditions (loss of cooling to the RCP seals). The perceived risk associated with the number of crews failing the annual operating test is provided in the Simulator Operational Evaluation matrix of NRC Manual Chapter 0609, Appendix I, Licensed Operator Requalification Significance Determination Process (SDP). The finding is of very low safety significance (Green) because less than 34 percent of the operating crews failed, the failed operating crews were remediated (i.e., the operating crews were re-trained and successfully retested) prior to returning to shift, and because there were no operating crew failures the previous year. The cause of this finding was directly related to the cross-cutting aspect of personnel training and qualifications in the Resources component of the Human Performance area, in that the licensee failed to ensure the adequacy of the training provided to operators to assure nuclear safety |
| 05000261/FIN-2011002-05 | 2011Q1 | Robinson | None | TS 3.5.3, ECCS Shutdown, required immediate actions to restore One ECCS RHR train to operable status when the required train was inoperable. Contrary to this on September 27, 2008, during the shutdown and on November 2, 2008, during the startup from a refueling outage RHR temperature was above the 250 degree Fahrenheit temperature limit for a combined total of approximately 15 hours. The cause of the violation was an inadequate review of operating experience which had identified the potential for voiding in the RHR system when responding to a loss of coolant accident if RHR temperature is too high. The licensee entered the issue into the corrective action program as NCR 367186. The finding was evaluated in accordance with IMC 0609.04, Significance Determination Process (SDP) Phase 1 screening worksheets. Because it represented an actual loss of safety function of both trains of RHR, an SDP Phase 2 analysis was attempted. The inspectors determined that the finding could not be adequately modeled using the Phase 2 process. An SDP Phase 3 analysis was performed for the deficiency using an at power (vice a shutdown evaluation) because the performance deficiency would manifest itself immediately after shutting down the unit or immediately preceding returning to power. The NRC\'s risk model was modified to reflect the total loss of RHR pumping capability due to either voiding of the pump suctions or the associated water-hammer event. The resulting analysis, including the risk contribution due to external sources, was less than 1E-6/year and the finding is GREEN. The dominant cut sets were medium and small break loss of coolant accidents that proceed immediately to core damage due to the lack of low pressure injection |
| 05000261/FIN-2011002-06 | 2011Q1 | Robinson | None | TS 5.4.1, Procedures, required preventive maintenance be accomplished on safety related systems in accordance with Regulatory Guide 1.33, Revision 2, Appendix A, 1978. Contrary to this in 2004, during preventive maintenance on the B Inverter, the sync board was not replaced as planned and the work order was closed as completed. This resulted in the sync board remaining in service beyond the vendor 10 year replacement recommendations. The 10 year life expired in 2009. As a result, the B Inverter failed during surveillance testing on June 24, 2010. The failure resulted in a loss of RHR temperature control and inoperability of the B EDG. The cause of the violation was inadequate review of the work order which did not track the sync board replacement deviation. The licensee entered the issue into the corrective action program as AR 406834. Significance Determination Process (SDP) phase 1 screening for the finding determined that the finding required a phase 2 shutdown risk assessment in accordance with Inspection Manual Chapter (IMC) 0609 Appendix G. A loss of RHR(LORHR) event assessment was performed for the June 24, 2010 event. The event risk assessment period was <3 days while in mode 5 (Plant Operating State (POS-2)). A condition assessment was performed to cover the likelihood of an inverter failure conditional on a loss of offsite power (LOOP) event covering the period between the failure of inverter B and the last successful demonstration of inverter B to synchronize properly (March 28, 2010 June 23, 2010). The major assumptions of the LORHR event assessment were an initiating event likelihood (IEL) of 1.0, reactor coolant system (RCS) time to boil of 8.6 hours, time to core uncover of 13.9 hours, full operator and equipment credit for RHR recovery, refueling water storage tank (RWST) makeup and feed capability due to availability of safety injection and charging systems. The LORHR sequences were (1) LORHR with failure to recover RHR before RCS boiling, successful RCS injection, failure to recover RHR before RWST depletion and failure to accomplish RWST makeup leading to core damage, and (2) LORHR, failure to recover RHR prior to RCS boiling and failure of RCS injection leading to core damage. The major assumptions of the LOOP condition assessment were an IEL of 2 for the duration in POS 1, IEL of 3 for the duration in POS2, full credit for emergency ac power due to availability of EDG A, ability to manually load EDG B and the availability of steam generator (S/G) cooling due to motor driven and turbine driven auxiliary feed water trains. The dominant LOOP condition assessment sequences were (1) LOOP, failure of AC power, failure to maintain S/G cooling with a failure to recover offsite power prior to core damage and (2) LOOP, failure of AC power, successful gravity feed, with failure to recover offsite power or EDGs prior to core damage. The LORHR event risk was mitigated by the low decay heat present during the event, the availability of RHR trains and indications, and ease of diagnosis and restoration of the loss of instrument bus power allowing a recovery of RHR flow control from the main control room. The LOOP condition assessment risk was mitigated by the fact that the inverter B failure was conditional upon a LOOP event occurring during the evaluation period and the availability of EDG A during the evaluation period with EDG B available but requiring manual loading. The phase 2 SDP risk evaluation including the event and condition assessments resulted in a risk increase of <1E-6 in core damage frequency, a Green finding of very low safety significance |
| 05000261/FIN-2011002-07 | 2011Q1 | Robinson | None | TS 3.4.9, Pressurizer, required Pressurizer heaters operable with a capacity of greater than or equal to 125 kW and capable of being powered from an emergency power supply. Contrary to this in December of 2008 the pressurizer heaters were inoperable for approximately 95 hours which exceeds the allowed outage time of 72 hours. The cause of the event occurred in the fall of 1979 in response to NUREG- 0578, TMI-2 Lessons Learned Task Force Status Report and Short-term Recommendations. The licensee revised procedure EI-15, Control Room Inaccessibility based on the assumption the pressurizer heater emergency power supply scheme was redundant. The cause of the violation was the licensee did not recognize the low pressurizer level heater cutoff relay was powered from the A train and would preclude energizing the required pressurizer heaters from the B train if the A train was inoperable. Immediate corrective actions included revising the implementing procedure to lift a control lead to allow the B EDG to power the required pressurizer heaters if needed during an event with the A EDG inoperable. The licensee entered the issue into the corrective action program as NCR 413865. The finding was evaluated in accordance with IMC 0609.04, Significance Determination Process. A regional Senior Reactor Analyst evaluated the performance deficiency using the Phase 3 protocol of the Significance Determination Process. Based upon the results of that evaluation, the performance deficiency was characterized as of very low safety significance (Green). The major assumptions of the evaluation included a one year exposure time, that the performance deficiency was only associated with a Loss of Offsite Power initiator and, that the lack of Pressurizer heaters eventually led to a loss of sub-cooled margin, which removed the steam generators as a viable heat sink and resulted in a feed and bleed safety injection condition. The postulated dominant accident sequence was a switchyard induced Loss of Offsite Power with Emergency Diesel Generator A out of service for test and maintenance. Neither offsite power nor Emergency Diesel Generator A was returned to service within one hour. Within that one hour operators were unable to preclude a feed and bleed safety injection. Consequently, the opened safety relief valve initiated a Small Break Loss of Coolant Accident. Operators then failed to place High Pressure Recirculation into service properly in response to the Small Break Loss of Coolant Accident. Therefore, the core was not cooled and core damage ensued |
| 05000261/FIN-2011002-04 | 2011Q1 | Robinson | Refueling Water Storage Tank Operability While On Purification | An Unresolved Item is being opened to provide for additional inspection in response to an NRC identified issue regarding Refueling Water Storage Tank (RWST) operability with the purification loop in operation. The inspectors noted on March 8, 2011, that the RWST purification loop had been in operation for approximately 14 hours. The piping and components of the purification loop are shown on plant drawings to be beyond the seismic qualification boundary for the RWST. The licensee had previously reviewed this issue using AR 422778 in late 2010 and determined it was acceptable to place the RWST on purification without declaring the RWST inoperable. The inspectors questioned the basis for that conclusion. The licensee removed the RWST from purification and put administrative controls in place to prevent use of the purification loop until the issue is resolved. The licensee is continuing to evaluate the use of the RWST purification loop and the impact on operability of the RWST. Additional review by the NRC is required following the completion of the licensees evaluation. This review will also determine whether this issue represents a performance deficiency. The issue will be identified as URI 05000261/2011002-4, Refueling Water Storage Tank Operability While On Purification |
| 05000261/FIN-2010005-01 | 2010Q4 | Robinson | Failure to Perform 5-year Vendor Manual Specified Reactor Coolant Pump Motor Inspections | The inspectors identified a Green finding for failure to perform vendor recommended inspections of the reactor coolant pump (RCP) motors. Visual inspections of the RCP stator assemblies were not performed at five year intervals in accordance with the vendor technical manual preventive maintenance instructions. Adequate justification for exceeding the five year interval was not provided. Inspection of the stator assembly in accordance with the vendor recommendations at a five year interval is expected to have identified any significant degradation requiring repairs. The licensee failed to conduct these inspections and a motor failure occurred on October 7, 2010. The licensee replaced the failed C RCP motor and will evaluate the preventive maintenance inspection interval. The licensee has entered this issue into the CAP as Nuclear Condition Report (NCR) 438509. The failure to partially disassemble the RCP motors and perform visual inspections of the rotor and stator assemblies was a performance deficiency that was within the licensees ability to foresee and correct, and therefore should have been prevented. The finding is more than minor because it adversely impacted the equipment performance attribute of the initiating event cornerstone and its objective to limit the likelihood of those events that upset plant stability and challenge critical safety functions during shutdown as well as power operations. Specifically, the C RCP motor failed causing a reactor trip. The finding, screened per Appendix A of IMC 0609, Significance Determination Process, was determined to have very low safety significance (Green) because although the stator failure damaged the number two and number three RCP seals, no damage to number one RCP seal occurred. The number one RCP seal is the primary reactor coolant system pressure boundary. A cross-cutting aspect was not assigned to the finding because the performance deficiency does not represent current performance. |
| 05000261/FIN-2010005-02 | 2010Q4 | Robinson | Licensee-Identified Violation | TS 3.8.2, AC Sources Shutdown, required immediate actions to restore an EDG to operable status when the required EDG was inoperable. Contrary to this on April 24, 2010, the B EDG was made inoperable for 3 hours and 22 minutes due to surveillance testing while the A EDG was inadvertently made inoperable due to an equipment clearance from April 18, 2010 to April 26, 2010. The cause of the violation was that the licensee did not understand the equipment clearances impact on the A EDG operability. Specifically, the automatic equipment loading feature in response to a station blackout had been defeated. Manual loading of the required equipment remained functional during the event. The licensee entered the issue into the CAP as NCR 395800 and removed the clearance to restore the B EDG to operable status. The event was determined to be of very low safety significance because when the B EDG was inoperable, manual loading of the required equipment on the A EDG was available, the refueling cavity was flooded and the dedicated shutdown diesel was also available. |
| 05000261/FIN-2010005-03 | 2010Q4 | Robinson | Emergency Diesel Generator Inoperable in Excess of Technical Specifications Completion Time Due to Output Breaker Failure | A violation of TS 3.8.1.B was identified when the B EDG was inoperable in excess of the TS allowed outage time. Enforcement discretion was exercised for this violation. No performance deficiency was identified. On February 22, 2010, the B EDG was removed from service for planned maintenance. During post maintenance testing the output breaker for the B EDG failed to close. The breakers failure to close was unrelated to the maintenance activity. The licensee entered the issue into the corrective action program as AR 382604 and initiated a root cause and extent of condition review. A new output breaker was installed and tested on February 24, 2010. The licensee determined the cause of the breaker failure was due to a vendor workmanship error, which included a defective Shunt Trip Attachment (STA) movable core in the breaker control circuit. Based on the failure mechanism, the licensee, using engineering judgment, concluded the B EDG had been inoperable for greater than the 7 days allowed by TS 3.8.1.B.4 and Condition C. The last successful breaker closure was January 28, 2010. This corresponded to approximately a 27 day period of inoperability. As discussed in the licensees root cause report, an inspection of the STA movable core revealed that the leading edge of the core was not chamfered to 1/32 as required by design specifications. Additionally, the leading edge of the moveable core exceeded the maximum outside diameter (OD) design specification by 0.004 in one area. The moving core slides within a brass sleeve on the STA. The brass sleeve inside diameter (ID) has a tolerance of 0.008. The moveable core must be free to rotate within the brass sleeve during STA operation. The investigation revealed the internal binding of the movable core occurred when the maximum OD region of the moveable core aligned with the minimum ID of the brass sleeve. Because the STA is procured from the vendor as part of a complete breaker or replaced as a complete assembly, the cause was not reasonably within the licensees ability to foresee and correct. An assessment of the significance of the event was performed by the inspectors. This review resulted in the matter being assigned a risk assessment of low to moderate significance. In addition, the licensees risk evaluation determined that the increase in core damage probability was also low to moderate significance. The event was mitigated by the redundant A EDG and Dedicated Shutdown Diesel Generator being available to respond to an event. The licensee concluded that actions to recover the B EDG, such as the discovery that the STA had positioned the trip bar in such a way which would not allow the breaker to close or replacing the affected breaker with a spare, could be accomplished in an estimated time frame which ranged from one to four hours. The inspectors reviewed the licensees assessment and corrective actions for the event, and determined they were appropriate to the circumstances. All similar breakers at the Robinson Plant which are susceptible to this failure have been inspected with no deficiencies noted. Prior to implementation of these inspections, satisfactory compensatory actions were put in place which ensured successful operation of similar breakers. The inspectors determined a violation of TS 3.8.1.B occurred since the B EDG was inoperable in excess of the TS allowed outage time (7 days). The inspectors determined that this violation was more than minor because it affected the equipment performance attribute of the Mitigating System cornerstone and because it affects the cornerstone objective of ensuring mitigating system availability. The inspectors determined that the breaker failure was not a performance deficiency because the cause of the failure was not reasonably within the licensees ability to foresee and correct to prevent the failure. Because a performance deficiency was not associated with this issue, it was not subject to evaluation under the formal Significance Determination Process (SDP) using Inspection Manual Chapter 0609. |
| 05000321/FIN-2010009-01 | 2010Q4 | Hatch | Acceptability of Liquid Filled Transformers in Fire Areas 2017 and 2019 | The team identified an unresolved item (URI) involving the requirements for the installation of high-voltage liquid insulated transformers installed indoors. This item is unresolved pending receipt and review of additional documentation. FA 2017 and adjacent FA 2019 contained liquid insulated 4160-600 V transformers. The insulating liquid in these transformers was Dow Corning PMX-561, which is a combustible silicone based liquid with an ignition temperature of 460 oF. The team identified that the equipment in the FAs did not appear to be consistent with the requirements described in NRC Position D.1.g of Appendix A to Branch Technical Position (BTP) APCSB 9.5-1, Guidelines for Fire Protection for Nuclear Power Plants, dated August 23, 1976, in that the FAs contained both high-voltage-high-current transformers insulated with combustible liquid, and safety-related equipment, without enclosure in a three-hour barrier and installing automatic fire suppression. The north and west walls of FA 2017 and the north, east, and west walls of FA 2019 are credited as two-hour fire rated fire barriers. Additionally, the room comprising FA 2019 did not have a three-hour rated wall, and had a leakage path under the door such that transformer insulating fluid could spread to the adjacent FA. The Hatch FHA contained exemptions from certain requirements of 10 CFR Part 50, Appendix R for the above stated requirements, obtained at the time that 10 CFR Part 50, Appendix R became effective, but the exemptions were based on having negligible fuel loading in the FAs. The team determined that the exemption request was based on the licensees belief that the original transformer insulating liquid represented negligible combustible loading, which was not the case at the time of the inspection. During the inspection, the team attempted to determine the actual fire endurance capabilities of the walls surrounding FAs 2017 and 2019 as well as the fire rating of various masonry block wall penetrations. However, this information could not be ascertained during the inspection. The licensee initiated condition reports (CRs) 201000869, 2010115004, 2010115915, and 2010115986 to address these issues in their corrective action program. The matter is unresolved pending receipt and analysis of information from the licensee necessary to determine whether FAs 2017 and 2019 meet the requirements of Position D.1.g of Appendix A to BTP APCSB 9.5-1 and the licensees fire protection program licensing basis. An unresolved item, URI 05000366/2010009-01, Acceptability of Liquid Filled Transformers in Fire Areas 2017 and 2019, is being opened pending receipt and review of this information. |
| 05000261/FIN-2010004-05 | 2010Q3 | Robinson | Failure to Correctly Implement a Systems Approach to Training for the Licensed Operator Requalification Program | (TBD) The inspectors identified an Apparent Violation (AV) of 10 CFR 55.59(c), Requalification program requirements , for the licensees failure to properly implement elements of a Commission approved program developed using a systems approach to training (SAT), that was implemented in lieu of meeting the requirements defined in 10 CFR 55.59 (c). The finding was entered into the licensees corrective action program as NCR-423232, NCR-423238, and NCR-423239. Corrective actions for this finding are still being evaluated. The licensees failure to properly implement elements of a Commission approved requalification program was a performance deficiency. The finding was determined to be more than minor because it was associated with the Initiating Events Cornerstone and affected the cornerstones objective to limit the likelihood of those events that upset plant stability and challenge critical safety functions during shutdown as well as power operations. Specifically, the failure to implement training requirements for Path-1 and perform adequate retraining of operators that demonstrated areas of weakness during operating tests contributed to operators failure to identify and implement actions to mitigate a loss of seal cooling to the reactor coolant pumps (RCPs) during the events of March 28, 2010. Contrary to Augmented Inspection Team Report 05000261/2010009, further inspection revealed that RCP seal injection was not adequate coincident with a loss of cooling to the thermal barrier heat exchanger to the B RCP. Using Manual Chapter Attachment 0609.04, Phase 1 - Initial Screening and Characterization of Findings, the inspectors determined the finding required a Phase 2 analysis because the finding could result in reactor coolant system (RCS) leakage exceeding Technical Specification limits. The Phase 2 analysis determined that this finding was potentially greater than green; therefore, a Phase 3 analysis is required by a regional senior reactor analyst due to an increase in the likelihood of an RCP seal LOCA. The significance of this finding is designated as To Be Determined (TBD) until the safety characterization has been completed. The cause of this finding was directly related to the cross cutting aspect of Personnel Training and Qualifications in the Resources component of the Human Performance area, in that the licensee failed to ensure the adequacy of the training provided to operators to assure nuclear safety. |
| 05000261/FIN-2010004-01 | 2010Q3 | Robinson | Failure to Have Adequate Work and Post Maintenance testing Instructions for the Volume Control Tank Comparator Module | A self revealing Green finding was identified for a failure to have adequate work orders to properly configure and post maintenance test the volume control tank (VCT) level comparator module. The licensees procedure ADM-NGGC-0104, Work Implementation and Completion, required that work orders contain all work activities necessary to perform all related work activities including Post Maintenance Testing (PMT). The licensees work orders for installing a jumper on the VCT level comparator module and for post maintenance testing failed to contain adequate instructions to properly configure (place jumper in correct location) and post maintenance test the volume control tank level comparator module. This resulted in the failure of the charging pump suction to automatically transfer from the volume control tank to the refueling water storage tank (RWST) when the auto transfer VCT low level setpoint was reached. The licensees identified corrective actions included repairing the subject VCT level module, reviewing the adequacy of other replacement NUS modules that have nonsafety control functions and revising the site specific PMT procedures to provide more specific guidance for ensuring that the control loop circuit is adequately tested. The failure to have adequate work order instructions to properly configure and post maintenance test the volume control tank level comparator module is a performance deficiency. This finding is greater than minor because the failure to auto transfer from the VCT to the RWST could cause a failure of the charging pump, resulting in the loss of seal injection which is a precursor to a seal LOCA. Using IMC 0609, Significance Determination Process, (SDP) Phase 1 Worksheet, the inspectors concluded that a Phase 2 evaluation was required since the finding could have likely affected other mitigation systems resulting in a total loss of their safety function. This issue was evaluated using IMC 0609, Appendix A (SDP Phase 2) as being potentially greater than green with loss of component cooling water (LOCCW) and loss of service water (LOSW) as the dominant sequences. A phase 3 SDP risk evaluation was performed by a regional senior reactor analyst in accordance with the guidance in IMC 0609 Appendix A utilizing the NRCs Robinson Standardized Plant Analysis Risk (SPAR) model. The VCT level comparator module performance deficiency resulted in a core damage frequency increase of less than 1E-6, Green. The risk was mitigated by the availability of the letdown and normal makeup charging pump suction sources, which would be available under certain conditions reducing the likelihood of an autoswap demand. Another factor which mitigated the risk is that the fire shutdown procedures for most fire areas specify use of a manual RWST supply valve. The performance deficiency is characterized as Green, a finding of very low safety significance. This issue has a cross-cutting aspect in the resources component of the human performance area because the licensee did not provide complete, accurate, and up-to-date work packages for the configuration and testing of the VCT comparator module. |
| 05000261/FIN-2010004-04 | 2010Q3 | Robinson | Failure to Establish an Adequate PATH-1 Emergency Operating Procedure | (TBD) The inspectors identified an apparent violation (AV) of Technical Specifications (TS) 5.4.1, Procedures , for the licensees failure to establish and maintain an adequate emergency procedure that ensured reactor coolant pump (RCP) seal cooling was maintained following a reactor trip. The licensee has entered this into the CAP as nuclear condition report (NCR) 423147. Corrective actions for this finding are still being evaluated. The failure to establish and maintain an emergency procedure that would ensure adequate reactor coolant pump seal cooling, preventing seal degradation and a possible seal LOCA was a performance deficiency. The finding is more than minor because it is associated with the Initiating Events Cornerstone and affected the cornerstone objective to limit the likelihood of those events that upset plant stability and challenge critical safety functions during shutdown as well as power operations, specifically a loss of seal cooling to prevent the initiation of a RCP seal loss of coolant accident (LOCA). Using Manual Chapter Attachment 0609.04, Phase 1 - Initial Screening and Characterization of Findings, the inspectors determined the finding required a Phase 2 analysis because the finding could result in RCS leakage exceeding Technical Specification limits. The Phase 2 analysis determined that this finding was potentially greater than green; therefore, a Phase 3 analysis is required by a regional senior reactor analyst due to an increase in the likely hood of an RCP seal LOCA. The significance of this finding is designated as To Be Determined (TBD) until the safety characterization has been completed. The cause of this finding had a cross-cutting aspect of Documentation, Procedures, and Component Labeling, in the Resources component of the cross-cutting area of Human Performance, in that the licensee failed to ensure procedures for emergency operations were adequate to assure nuclear safety. |
| 05000261/FIN-2010004-03 | 2010Q3 | Robinson | Deficiencies in Non Safety-Related Cable Installation Result in Fire and Reactor Trip | A self-revealing Green finding was identified for the licensees failure to adequately follow guidance in a design change package for the installation of non safetyrelated 4kV cables. This resulted in cables with design features inappropriate for the application being installed and eventually led to a fire and a reactor trip. Specifically, the licensee failed to follow the cable vendor recommendations and a self-imposed administrative requirement/standard for cable installation contained in cable specification L2-E-035, Specification for 5,000 Volt Power Cable. The licensee entered this into the CAP as NCR 390095. As corrective actions, the licensee replaced the cable, conduit and other damaged equipment, including evaluation on damage to cables in overhead, and the feeder cables to station service transformer (SST) 2E and 4kV bus 5. The failure to follow the guidance in the design change package to install non safetyrelated cables between Bus 4 and Bus 5 in accordance with their design change program and vendor and cable installation specifications was a performance deficiency. This finding was determined to be more than minor because it affected the Initiating Events Cornerstone objective of limiting events that upset plant stability, and was related to the attribute of Design Control (i.e., Plant Modifications). Specifically, the inadequate cable modification was determined to be the root cause of the reactor trip that occurred on March 28, 2010. This deficiency also paralleled Inspection Manual Chapter 0612, Appendix E, Example 2.e, as the licensee did not follow their own administrative requirements and vendor recommendations for cable installation. The performance deficiency was screened using Phase 1 of Inspection Manual Chapter 0609, Significance Determination Process, which determined that because the finding increases the likelihood of a fire, a Phase 3 SDP analysis was required. A phase 3 SDP risk evaluation was performed by a regional senior reactor analyst in accordance with the guidance in IMC 0609 Appendix F utilizing the NRCs Robinson SPAR model. The Phase 3 analysis determined the finding to be of very low safety significance (Green) because the core damage frequency increase was less than 1E-6. There is not a crosscutting aspect associated with the finding because the performance deficiency involving the cable installation occurred greater than 20 years ago and does not reflect current licensee performance. |
| 05000261/FIN-2010004-02 | 2010Q3 | Robinson | Failure to Design and Implement a Simulator Model that Demonstrated Reference Plant Response | A self-revealing Green NCV of 10 CFR 55.46(c), Simulation Facilities, was identified for a plant referenced simulator used for administration of operating tests not correctly modeling the reference plant. A loss of electrical power that resulted in a loss of component cooling water (CCW) to the reactor coolant pump seals was not properly modeled in the simulator. When power to safety-related 480 volt bus E-2 was transferred to the emergency diesel generator in the reference-plant, FCV-626, thermal barrier heat exchanger outlet isolation flow control valve, closed. The simulator modeled FCV-626 to respond to CCW flow through the valve and did not model the effect of a loss of power to the valve operator and associated control circuit. Consequently, with a loss of power to bus E-2, the simulator model allowed this valve to remain open. The licensee documented the issue in Significant Adverse Condition Investigation Report, 390095. As corrective action the licensee changed the simulator modeling to match the plant configuration. The inspectors determined that the failure of the simulator to accurately demonstrate reference plant response was a performance deficiency. This finding was more than minor because it affected the human performance attribute of the initiating events cornerstone in that the unexpected closure of FCV-626 raises the likelihood of human error in response to a loss and subsequent re-energization of the E-2 Bus. This could challenge reactor coolant pump seal cooling and result in reactor coolant pump seal failure. The finding was evaluated using the Operator Requalification Human Performance SDP (MC 0609, Appendix I) because it was a requalification training issue related to simulator fidelity. The finding was of very low safety significance (Green) because the discrepancy did not have an impact on operator actions resulting in a total loss of RCP seal cooling and subsequent increase in reactor coolant system (RCS) leakage. There is not a cross-cutting aspect associated with the finding because the performance deficiency involving the simulator modeling occurred over 3 years ago and does not reflect current licensee performance. |
| 05000424/FIN-2010006-01 | 2010Q3 | Vogtle | Control Room Fire Alternate Shutdown Evaluation (X4C2301S035) Does Not Reflect Integrated Plant Response | The team identified an unresolved item (URI) related to the Control Room Fire Alternate Shutdown Evaluation (CRFASE), calculation number X4C2301S035. Specifically, the team found that the CRFASE does not reflect integrated automatic plant response to fire in the MCR requiring shutdown from the RSPs. Description: The CRFASE is an evaluation of the impact of a fire in the MCR on the operators ability to safely shut down the plant from outside the MCR. The evaluation addresses discreet spurious operation concerns on a system basis. The CRFASE provides time constraints and compensatory measures used to develop the operator actions, and sequencing of these actions, in procedure 18038-1, Operation from Remote Shutdown Panels. During review of procedure 18038-1 and the CRFASE, the team questioned whether certain operator actions contained in step 3 of procedure 18038-1, if unable to be performed from the MCR, would be able to be performed within established time constraints in order to prevent and/or mitigate the adverse effects of spurious actuations. These time constraints, adverse spurious actions, and the impact on the plant of these spurious actuations are described in the CRFASE. Specifically, the team questioned whether reactor coolant pumps #1 and #4 would be able to be tripped early enough from the RSP in time to prevent depressurization of the reactor coolant system to the safety injection (SI) actuation set point, in the event one pressurizer spray valve spuriously opens. The team also questioned whether main steam isolation valves (MSIVs) would be closed from the RSP in sufficient time to minimize the chances of a significant overcooling transient (as described in the CRFASE) in the event the MSIVs were not closed from the MCR in step 3. Subsequent to the on-site inspection, the licensee developed a simulator exercise guide for the purpose of validating the time necessary for an operating crew to perform the steps in procedure 18038-1, through the point of tripping reactor coolant pump (RCP) #1 and #4 from the RSP, given immediate evacuation of the MCR and subsequent spurious operation of a pressurizer spray valve. The licensee stated that the time at which the pressurizer spray valve was set to open during the simulator exercise was based on a timing analysis contained in Request for Engineering Review RER C071912101, Safe Shutdown Time Critical Operator Actions in 18038-1/2 and 17103A-C. When validating the simulator exercise guide, the licensee found that the CRFASE does not reflect integrated plant response for a control room fire as predicted through simulation. Simulated plant response was different from the response described in the CRFASE, in that an automatic SI actuation occurred approximately 6 minutes after plant trip due to decreasing RCS pressure arising from RCS cooldown caused by high auxiliary feedwater (AFW) flow. Additionally, in the simulated plant response, the SI actuation automatically isolated instrument air to containment, which caused the pressurizer spray valve to close before spurious operation of the valve was input into the simulator scenario in accordance with the timing analysis. As a result of questions raised by the team during subsequent in-office inspection of this issue, the licensee initiated Condition Report (CR) 2010112114 to revise the CRFASE to review integrated plant response for a control room fire. In a telephone call with the licensee on October 4, 2010, the team stated that additional information would be required concerning the nature and extent of differences between plant response specified or assumed in the CRFASE and simulated or actual plant response. The team discussed the nature of the additional information required in telephone calls with the licensee on October 4, 2010, January 6, 2011, and January 11, 2011. On January 26, 2011, the licensee provided information concerning integrated plant response obtained from plant-referenced simulator scenarios, relative to spurious component actuations and plant conditions described in the licensees CRFASE. During an initial review of this material, the team identified additional questions regarding the new information. During a final briefing of the inspection on February 9, 2011, the licensee informed the team that the information provided on January 26, 2011, needed to be revised for clarification, and additional information would be provided. This additional information is necessary for the team to determine whether the plant response to a control room fire as described in the CRFASE represents a performance deficiency, and to determine whether procedure 18038-1 is adequate for maintaining safe plant conditions while performing shutdown outside the MCR. A URI was opened pending receipt and review of this additional information which is identified as URI 5000424;425/2010006-01, Control Room Fire Alternate Shutdown Evaluation (X4C2301S035) Does Not Reflect Integrated Plant Response. |
| 05000261/FIN-2010009-05 | 2010Q2 | Robinson | Corrective Action for Operating Crew Performance Issues | To assess the extent of condition for the operator performance issues demonstrated during this event, the team reviewed a sample of simulator crew evaluation forms spanning the period of February 2008 to February 2010. The team identified multiple examples of operating crew weaknesses identified by training, relative to monitoring and control of major plant parameters. Of the six packages reviewed, four contained comments summarized as follows: February 27, 2008 unaware of steam dumps open; no attempt at RCS temperature control March 3, 2008 crew not clear if steam dumps actuated February 19, 2009 pressurizer level control post-trip was not anticipated; S/G level control needed improvement February 24, 2009 slow to identify steam dump malfunction; post- trip trends of associated parameters not provided The team noted that even though the evaluations highlighted the operators responsibility for monitoring and controlling major plant parameters, this emphasis was not effective in achieving the level of performance necessary to stabilize the plant following the uncontrolled cooldown that occurred during this event. The team concluded that additional inspection is warranted to determine if the licensees corrective action program is effective in capturing and addressing operating crew performance weaknesses. The team noted that the licensee also identified this issue regarding operating crew performance standards as part of their event investigation. This review will also determine if this issue represents a performance deficiency. An Unresolved Item will be opened pending completion of this review. The URI is identified as 05000261/2010009-05, Corrective Action for Operating Crew Performance Issues. |
| 05000261/FIN-2010009-10 | 2010Q2 | Robinson | Failure of Charging Pump Suction Valves to Automatically Transfer Due to Errors in Implementing a Instrumentation Component Upgrade | Following the cable fault and resultant reactor trip, VCT level decreased and reached a low level set point that should have automatically transferred the suction source for the running charging pump to the RWST. The transfer did not take place as designed. The control circuitry which implements this transfer utilizes two VCT level transmitters. When each transmitter senses a low level, it energizes a relay via a comparator. When both relays are energized, and their contacts are closed, the circuit for opening the charging pump suction from RWST valve (LCV-115B) should be made up and the valve should open. Then, when LCV-115B opens, a signal is generated to close the VCT suction valve (LCV-115C.) One of the relays in the LCV-115B circuit was driven by an older style Hagan level comparator, and the other relay was driven by a newer style NUS comparator. Different NUS comparator configuration options, such as electromechanical relay or solid state output, can be made by placing plug-type jumpers at different locations on the circuit board. The licensees post-event troubleshooting revealed that the NUS comparator was not properly configured when it was installed in 2008. The NUS comparator should have been configured to have its output function operate in the solid state mode and energize the control relay when a low level was sensed. When the comparator was configured in 2008, the placement of jumpers resulted in an electromechanical relay output, which was only capable of de-energizing the control relay upon low level. As a result, the control relay driven by the NUS comparator was in the energized state when level in the VCT was normal. When level in the VCT decreased below the level at which the suction to the charging pumps should have transferred, the associated valves did not reposition because the relay driven by the NUS comparator was de-energized and the valve open circuit was not made up. The licensee did not detect the incorrect configuration of the NUS comparator after installation because of the limited scope of the post-installation testing. When the new comparator module was calibrated the bistable trip light responded as intended, satisfying the test acceptance criterion. The output contacts were not checked during the calibration and the licensee did not perform an integrated test, such as simulating a low VCT level, to confirm the two valves repositioned. The licensee replaced the VCT level Hagan comparator with an NUS comparator as part of a larger project to provide a replacement for obsolete Hagan comparators. Licensee engineers stated that about 80 percent of the Hagan comparators had been replaced with NUS comparators at the time of the AIT inspection. The team questioned the extent of condition for potential similar errors in replacement comparators, i.e. incorrect placement of jumpers and inadequate testing for detecting errors. The licensee noted that comparators used to perform reactor protection system functions, safety injection functions and certain other functions were subject to Technical Specification surveillance testing, which provided a check of the comparator output contacts. The licensee also pointed out that the circuit in question may have been unique in that only one of the comparators used in the two-out-of-two logic had been changed to the new NUS module. If two NUS modules had been installed, both containing the incorrect configuration for the jumpers, the transfer from VCT to RWST suction would have taken place with a normal VCT level and the problem would have been self revealing. The licensee stated that many control functions using the new NUS modules would alarm when the bistable actuates, making a similar problem self revealing. The licensee controlled the substitution of NUS comparators for Hagan comparators under the plant modification process using Engineering Evaluation EE-92-144. The licensee controlled component removal and installation within the maintenance process. The installation of the comparator for the charging pump suction transfer control circuit was accomplished under Work Order 011162348 in September 2008. Work order instructions directed an I&C technician to refer to the calibration procedure to determine the desired comparator configuration and refer to NUS instruction book EIP-M-DAM800 to determine the placement of jumpers necessary to implement that configuration. The placement and removal of jumpers was translated to work instructions which were reviewed and verified by an I&C system engineer. The licensee stated their planned corrective actions would include a review of all control circuits incorporating NUS comparators to confirm these circuits will operate properly. In cases where a review indicates proper operation cannot be assured, the licensee stated that appropriate testing will be performed. In addition, the process for implementing any future NUS comparator installations will be strengthened to preclude the problems described above. The team determined the failure of the suction for the charging pumps to automatically transfer from the VCT to the RWST upon low level in the VCT was caused by an error in the work instructions describing the placement of jumpers when a VCT level comparator was replaced. Additionally, the licensees post-maintenance testing was not adequate to detect the problem. Additional review by the NRC will be needed to determine whether these problems represent a performance deficiency. An Unresolved Item will be opened pending completion of this review. The issue is identified as URI 05000261/2010009-10, Failure of Charging Pump Suction Valves to Automatically Transfer Due to Errors in Implementing an Instrumentation Component Upgrade. |