Semantic search

This page or action requires JavaScript to work. Please enable JavaScript in your browser or use a browser where it is supported, so that functionality can be provided as requested. For further assistance, please have a look at the noscript help page.

Search Clear all entries

	Quarter	Site	Title	Description
05000269/FIN-2014002-01	2014Q1	Oconee	Inadequate Procedure to Ensure Adequate Piping Weld Inspections	A NRC-identified potentially Greater than Green Apparent Violation (AV) of 10 CFR Part 50, Appendix B, Criterion V, Instructions, Procedures, and Drawings, was identified when the licensee failed to ensure that procedure NDE-995, Ultrasonic Examination of Small Diameter Piping Butt Welds and Base Material for Thermal Fatigue Damage, was adequate to achieve acceptable coverage for the ultrasonic (UT) examination of weld 1-RC- 201-205. NDE-995 did not contain the necessary steps to achieve acceptable coverage for UT examinations when limitations were encountered. The licensee entered this finding into their corrective action program as PIP O-13-13168. The failure to ensure that station procedure NDE-995 was adequate to achieve acceptable coverage for the UT examination of weld 1-RC-201-205 was more than minor because it affected the Design Control attribute of the Initiating Events cornerstone and adversely affected the cornerstone objective in that an undetected crack resulted in reactor coolant system pressure boundary leakage and a forced shutdown of Unit 1. The inspectors determined that detailed risk analysis was required. There was no immediate safety concern because the crack was repaired. The inspectors determined this finding has a cross-cutting aspect of H.7 in the Documentation component of the Human Performance area because the licensee did not create and maintain complete, accurate, and up-to-date documentation in procedure NDE-995 to ensure acceptable coverage for UT examinations.
05000261/FIN-2010012-02	2010Q4	Robinson	C RCP Motor Failure and Seal Damage	The inspectors identified an URI associated with the failure of the C RCP motor and damage to two of the C RCP seals. Upon review of the licensees root cause evaluation of the failure of the C RCP motor and seals, the inspectors identified that the licensee was aware of vibration and age related degradation vulnerabilities of the C RCP motor windings, and planned to rewind the motor in order to eliminate these vulnerabilities. However, the licensee did not rewind the motor prior to its failure. This item is unresolved pending further review and evaluation of the licensees refurbishment plans and failure susceptibility analysis. The licensees root cause evaluation for the failure of the C RCP motor identified that vibration induced winding degradation, combined with age related thermal degradation of motor winding insulation, led to a turn-to-turn fault in the motor stator end windings. This turn-to-turn fault propagated to a phase-to-phase fault and the fault current traveled to the motor rotor and eventually through the number two and three seals. Laboratory analysis showed that the seals had evidence of arcing damage. The licensees root cause evaluation report also states that the licensee was aware of these degradation vulnerabilities and, in 2003, formulated a motor rewind plan for all of their RCPs. However, the C RCP that failed on October 7, 2010, had not been rewound to eliminate the end winding vibration degradation mechanism prior to its failure. Additionally, the replacement RCP motor currently installed as C RCP motor has not been rewound to eliminate the end winding vibration degradation mechanism. Pending the results of this additional inspection an Unresolved Item will be opened and designated as URI 05000261/2010012-02, C RCP Motor Failure and Seal Damage.
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.
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-2010006-01	2010Q3	Robinson	Failure to Correct a Control Power Fuse Defect in 4kV Breaker 52/24	A self-revealing finding of very low safety significance was identified for the licensees failure to follow the sites CAP procedure, CAP-NGGC-0200, Corrective Action Program, Revision 26; in that a degraded control power condition for the non-vital 4kV Bus 5 feeder breaker 52/24 was not identified and evaluated through an NCR which resulted in inadequate corrective actions leading to a plant trip and a complicated plant fire. The licensee implemented corrective actions to replace the affected breaker and inspect all breakers potentially affected by the same degraded control power condition This finding is more than minor because it is associated with Equipment Performance attribute of the Initiating Events Cornerstone and affects the cornerstone objective in that the failure to evaluate and correct the breaker position indicating light, which indicated the lack of breaker control power, resulted in the breaker failing to isolate an electrical fault, resulting in a reactor trip. The inspectors used NRC IMC 0609, Attachment 4, Phase 1 Initial Screening and Characterization of Findings, to evaluate the significance of this issue and determined that this finding contributed to both the likelihood of a reactor trip and the likelihood that mitigation equipment or functions will not be available. Therefore, further significance determination analysis was performed in accordance with IMC 0609, Appendix A, Determining the Significance of Reactor Inspection Findings for At-Power Situations The inspectors conducted a Phase 3 analysis and determined this finding was of very low safety significance because the performance deficiency did not affect the mitigating capabilities of the auxiliary feedwater system and the feed and bleed safety function. This finding has a cross-cutting aspect in the area of problem identification and resolution associated with the corrective action program component because the licensee failed to implement the corrective action program with a low threshold for identifying the issue, and ensuring that the issue was identified completely, accurately, and in a timely manner commensurate with its safety significance (P.1.a).
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.
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-2010009-04	2010Q2	Robinson	Fidelity of Plant-Referenced Simulator	A review of simulator performance and event data by the team confirmed one simulation deficiency which had been identified by the licensee as part of their event review. When power to safety-related 480 volt Bus E-2 was transferred to the emergency diesel generator, FCV-626 (thermal barrier heat exchanger outlet isolation flow control valve) closed unexpectedly. As discussed in more detail in the Section 4.5, Unexpected Closure of FCV-626, the as-built plant configuration resulted in the valve closing on a loss of power. This response was not obtained in the simulator because the simulator modeling of FCV-626 was based solely on CCW flow through the valve and did not take into account power to the valve operator and associated control circuit. Consequently, in simulator scenarios which included a loss of power to Instrument Bus 4, this valve remained open. Because the plant reference simulator did not demonstrate expected plant response for a loss of Instrument Bus 4, the team identified the need for additional NRC review to determine the adequacy of fidelity of the plant reference simulator for conducting loss of component cooling system control manipulations and plant evolutions. 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 05000261/2010009-04, Fidelity of Plant-Referenced Simulator.
05000261/FIN-2010003-01	2010Q2	Robinson	Failure to determine the cause of and take corrective actions to preclude repetition of an identified programmatic deficiency in foreign-material-exclusion controls.	The inspectors identified a violation of 10 CFR 50, Appendix B, Criterion XVI, for the licensees failure in 2004 to determine the cause of a programmatic deficiency in foreign-material-exclusion (FME) controls, which resulted in steam generator tube leakage. This licensee entered the issue into the corrective action program as AR 272388 following the issuance of URI 05000261/2008002-01. A revised extent of condition and all corrective actions to the FME program were implemented in 2008 Failure to evaluate FME programmatic deficiencies in AR 115704 or in any other NCR since 2004 until the issuance of URI 05000261/2008002-01 is a performance deficiency. The inspectors initially screened this issue in accordance with Inspection Manual Chapter 0609 Appendix J for URI 05000261/2008002-1. This screening directed an additional operating cycle be reviewed to provide a basis to evaluate the effectiveness of the licensees corrective actions. Based on the steam generator tube performance following the most recent refueling outage, with respect to no potential tube ruptures (all tubes sustained 3 times delta Pressure for normal operation) or tubes that should have been repaired as a result of previous inspections, the issue was screened in accordance with Manual Chapter 0609 Appendix A. This finding is more-than-minor because it affects the Equipment Performance attribute of the Initiating Events Cornerstone, in that deficiencies in foreign-material-exclusion controls could allow foreign material to enter the steam generators, and the foreign material could initiate a steam generator tube leak or rupture. The finding has very low safety significance because no significant tube damage occurred during the extended significance determination review. The finding is not indicative of current performance in that the timeframe of the performance deficiency was 2004-2007 and therefore a cross-cutting aspect will not be assigned to this issue.
05000261/FIN-2010009-08	2010Q2	Robinson	Deficiencies in Non Safety-Related Cable Installation	To determine the circumstances surrounding the fault in the cable that led to the first electrical disturbance and subsequent reactor trip, the team performed the following activities: Determined details of the cable construction including conductor size, insulation thickness and material, and type of shielding using the manufacturers data sheet Compared the cable construction to system requirements and standard industry practice Reviewed relevant portions of the plant modification that installed the cable Viewed the site of the cable fault Reviewed cable records to determine where other similar cables are installed in the plant Interviewed engineering staff involved with the electrical distribution systems and components Reviewed the licensees causal analysis for the cable fault Evaluated the licensees proposed corrective actions The cable that faulted did not meet many of the specifications for the design change that installed the cable. This contributed to the cable failure. The cable, manufactured by the Rome Cable Corporation (Rome), was installed in 1986 when 4 kV Bus 5 was installed as an extension of Bus 4 per Plant Design Change Number DCN-851. The cable, identified as C21344A, served as the interconnection between 4 kV Buses 4 and 5 and was comprised of two conductors for each of three phases. The cable was installed in two steel conduits, with each conduit containing all three phases. As noted in Section 2.1, all 4 kV buses at Robinson are non safety-related. The Bill of Materials for DCN-851 indicated that the cable should be in accordance with Standard Specification L2-E-035 for 5,000 Volt Power Cable. However, the Bill of Materials did not indicate a purchase order number for the cable that faulted, as it did for other cables installed by the modification, such as 3/c No. 12 AWG cable. Records reviewed by the team indicated that the cable came from reel number HBR-13505. Differences between Standard Specification L2-E-035 and the actual installed Rome cable are listed below: L2-E-035 called for coated copper conductors. The installed cable had uncoated conductors. L2-E-035 called for all cables to be provided with an outer jacket. The installed cable did not have a jacket. L2-E-035 called for cable insulation and jacketing that was self-extinguishing and non-propagating with regard to fire as described in IEEE 383-1974, Type Test of Class 1E Electric Cables, Field Splices, and Connections for Nuclear Power Generating Stations. The Rome catalogue data made no claim as to fire propagation properties. The event demonstrated that the cable lacked fire propagation properties because 1) the cable ignited following the fault, 2) the cable did not self extinguish after the fault was denergized, and 3) flame was propagated along the cable. L2-E-035 called for 133 percent insulation level and insulation shielding if specified in the purchase order. The installed cable did not have either of these features. The cable consisted of single conductor 500 MCM uncoated copper with 130 mils of cross-linked polyethylene insulation rated for continuous operation at 5 kV and 90 degree Celsius. The insulation thickness was determined from the overall cable diameter and from the licensees measurement of conductor diameter. The manufacturers catalogue information (SPEC 7155 dated January 1, 1991) stated that an insulation thickness of 120 mils is suitable for applications requiring 100 percent insulation levels. However, due to the high-resistance grounding scheme used on the Robinson 4 kV electrical system, an insulation level of 133 percent or 173 percent was required, depending on how long a ground fault could remain on the system. The significance of not having adequate insulation thickness was that, should a single line to ground fault occur the voltage on the two un-faulted phases would exceed the rating of the insulation. The cable did not have a jacket. The significance of not having a jacket was that the cable insulation was more vulnerable to damage during installation. Also, the jacket, if installed, would have provided a buffer between the insulation and grounded metal parts, such as the conduit or bus enclosure. The cable did not have an insulation shield. When an insulation shield is not installed, the electric field will be partly in the insulation and partly in whatever lies between the insulation and ground. This situation could be conducive to corona if a thin layer of air lies between the insulator surface and ground, which can lead to insulation deterioration. IEEE 666-1991, Design Guide for Electric Power Service Systems for Generating Stations, Section 12.3.6 states: Power cables rated 5 kV and over should be equipped with insulation shield. The significance of not having a grounded insulation shield was that voltage stress on the insulation was not symmetrical and uniform around the circumference, but rather greater at points where the insulation contacted a grounded surface, such as a metal conduit, than at other points around the circumference. The following information indicated that shielded cable was originally intended for this cable: 1) Design Change Notice No. 6 to DCN-851 changed the termination detail from one depicting the grounding of shield wires to one with no shield wires, and 2) installation instruction 4.35 directed installation of a stress cone for cable C21344A, which would be needed only for a shielded cable. Cognizant licensee engineers stated that the Rome cable installed as part of the Bus 5 modification was different than other 4 kV cable installed at Robinson and was used only for the Bus 4 to Bus 5 connection and the feeder from Bus 5 to station service transformer 2E. During the inspection, the licensee did not present any documentation explaining or justifying why the installed cable for the Bus 5 modification was different than Standard Specification L2-E-035 and the typical cables installed in the plant. The team reviewed the 4 kV cables connected to Buses 1 through 5, and found this statement to be correct. All the 4 kV cables connected to Buses 1 through 5, except for the two cables mentioned above, met or exceeded standard specification L2-E-035, with at least 133 percent insulation and insulation shield. In addition to construction details of the faulted cable, the team reviewed various design considerations related to the cable. The ampacity of two 500 MCM, 90 degree Celsius, cables installed in conduit in free air is 954 amperes. The team estimated the maximum continuous load on Bus 5 as 493 amperes; 216 amperes for the 1750 HP Circulating Water Pump and 277 amperes for the 2000 kV station service transformer. The overcurrent relays were set at 1000 amperes. Therefore, the cables were not overloaded during normal operation. The conduits were the correct size for the cables installed within them. The number of bends in the conduits did not exceed the recommended maximum number of bends. Therefore, pulling tension limits should not have been exceeded during installation. This did not preclude the possibility that the three single conductors became twisted as the cable was pulled through three 90 degree bends. The licensees Event Review Team (ERT) visually examined the faulted cable and the station service transformer 2E feeder cable and determined the three single conductors were twisted. Twisting of one conductor around the other two conductors could result in jamming of the cables in the conduit since the combined diameter of the twisted cables would be greater than the inside diameter of the conduit. The twisting would have led to excessive pulling force being applied during cable installation. The required pulling force is proportional to the side wall pressure exerted on the cable at a bend. Because of the extensive damage resulting from the length of time the fault was energized, the failure mechanism could not be determined with absolute certainty. The licensees causal analysis determined with a fair degree of certainty that the initial fault occurred at a point where the conduits terminate at the top of Bus 5 switchgear. After consideration of the above facts and review of the licensees causal analysis, the team concluded that the failure mechanism probably involved one or more of the following factors: Degradation of the insulation at the surface of the cable due to corona Damage to the insulation due to inadvertent twisting of the three conductors during the pulling-in process resulting in excessive side-wall pressure at one or more of the three 90 degree bends in the conduit Rubbing of the cable against the conduit or switchgear top plate due to turbine building vibration A secondary fault at the Bus 4 cable compartment for circuit breaker 52/24 was caused by plasma gas migrating inside the conduit and through a hole in the conduit seal, along with terminations that were not taped. The ERT postulated that the hole was caused by pressure built up in the conduit as a result of the fault. The ERT further postulated that this secondary fault at circuit breaker 52/24 created permanent degradation of the insulation at that location. All of the cable within the compartment was completed destroyed when Bus 4 was reenergized about four hours after the initial fault was cleared. The licensee stated that corrective actions related to the cable failure would be to replace the Rome cable feeding station service transformer 2E before plant startup. The licensees Significant Adverse Condition Investigation Report for the event states that a search, using catalog identification numbers, was made across the Progress Energy fleet for this type of cable or similar cable and none was found. The licensee did not believe revisions were needed to the design control process because the process had been changed earlier to preclude the problems described herein, i.e. lack of proper control over purchasing and field changes. The team concluded that the apparent root cause of the initial cable failure and subsequent associated short-circuits was poor quality control over the non-safety-related modification process for installing the cable. A cable of lesser quality than other 5 kV cables installed throughout the plant was installed as a substitute during this modification. The cable terminations were not taped and the cable was not restrained to prevent rubbing. The consequence of the cable fault was a reactor trip. Because of the magnitude of the electrical fault, the reactor trip would have occurred regardless of whether bus tie circuit breaker 52/24 was fully functional. The resultant voltage transient decreased RCP speed which lowed RCS flow and initiated a reactor trip. This occurred faster than the time delay overcurrent protective relays associated with circuit breaker 52/24. Additional review by the NRC will be needed to determine whether the cable installation represents a performance deficiency. An Unresolved Item will be opened pending completion of this review. The issue will be identified as URI 05000261/2010009-08, Deficiencies in Non Safety-Related Cable Installation.
05000261/FIN-2010009-09	2010Q2	Robinson	Failure to Repair Circuit Breaker 52/24 Resulting in Breaker Being Unable to Operate	Circuit breaker 52/24 is the non safety-related tie circuit breaker between 4 kV Bus 4 and Bus 5. Following an electrical fault on cabling between this breaker and Bus 5 as described in Section 4.1, the breaker failed to open to clear the fault due to a lack of control power. The team reviewed equipment records related to circuit breaker 52/24 and determined that Work Request 357740 was written in November 2008 to repair the closed position indicating light located on the front of the circuit breaker. Because the closed position light would not illuminate after the light bulb was replaced, licensee personnel assumed the problem involved the socket for the bulb. Although the licensee had subsequently developed a work order to repair the socket, the licensee had not performed any additional repairs up to the time of the event. A number of opportunities existed to identify the source of the problem, including additional work requests and walkdowns by the system engineer. The additional work requests were canceled to the work order and the system engineer failed to recognize the potential impact of the failed indicating light regarding breaker operation. Following the event, the licensee determined that one of the control power fuses in the breaker trip circuit was failed. Laboratory examination by the licensee revealed that the fuse had a cracked internal element. The licensees ERT found that the overcurrent relays and the circuit breaker were fully functional. The failed fuse caused the breaker trip circuit to be deenergized, resulting in the indicating lamp being off and preventing the circuit breaker from tripping. Operations, Maintenance, and Engineering personnel did not fully understand the significance of the deenergized breaker indicating light. Operations personnel did not request an engineering assessment when they reviewed the work order. However, because station engineering was independently aware of the condition, it is not evident that a request for an engineering assessment would have resulted in a different outcome. The broken fuse, style LPN-RK-30SP, was manufactured by Bussman Division of Cooper Industries. As part of their corrective actions for this problem, the licensee checked the resistance of 16 fuses of the same style to determine whether any incipient degradation was taking place. The tested group included in-service fuses of various sizes as well as three new fuses. The licensee determined all the fuses had acceptable resistance readings. The licensee stated they would also provide training to appropriate plant personnel regarding this event and expectations for response to circuit breaker indicating lamps being off when they should be on. (Note: On April 14, 2010, the NRC issued Information Notice 2010-09, Importance of Understanding Circuit Breaker Control Power Indications, which described the problem with circuit breaker 52/24 control power). Section 4.1 states that, because of the high magnitude of the fault current, a reactor trip would have occurred as a result of the March 28 event, regardless of whether circuit breaker 52/24 was fully functional. However, for potential faults resulting in smaller currents, proper operation of circuit breaker 52/24 would prevent a reactor trip. The team concluded the licensee failed to understand the possible implications of circuit breaker 52/24 indicating light being off and should have pursued the issue in a timely manner. The problem existed for approximately 17 months until this event revealed the circuit breaker was unable to isolate a fault condition. Additional review by the NRC will be needed to determine whether the failure to correct, in a timely manner, a problem with the indicating light for circuit breaker 52/24 and the underlying problem with the control power fuse represents a performance deficiency. An Unresolved Item will be opened pending completion of this review. The issue will be identified as URI 05000261/2010009-09, Failure to Repair Circuit Breaker 52/24 Resulting in Breaker Being Unable to Operate.
05000261/FIN-2010009-06	2010Q2	Robinson	Adequacy of Emergency Operating Procedure Background Documents	From interviews, the team determined that the control room operators, in responding to the event, relied exclusively on actions and guidance explicitly described in EOPs. The operators did not consider mitigating actions that would have stabilized the plant that were not explicitly contained in these procedures, such as shutting the MSIVs. The emergency procedures being implemented centered on the Path-1 EOP. From a review of the plant procedures used by operators to respond to this event, the team determined that certain Path-1 procedure steps required operators to rely on their knowledge because these steps did not contain detailed (rule-based) guidance. The team observed that Path-1 is a flow diagram that assists with diagnostics but does not consistently provide acceptance criteria and alternate actions. The team determined that, in general, implementation of the Path-1 EOP relies more heavily on operator knowledge-based behavior versus the rule-based behavior emphasized in WOG Emergency Response Guidelines. The team noted that common industry practice among Westinghouse technology plants is to utilize a two-column page format for EOPs and to also provide more explicit detail regarding specific parameters to be checked and specific components to manipulate within each step. The team observed that EOPs did not contain explicit guidance to fully isolate ongoing steam flow in all cases. For example, End Path Procedure (EPP) Foldout A Step 6 MSR Isolation Criteria does not contain additional contingency actions in the event the specified action cannot be taken or is not effective (i.e. loss of power to MSR steam supply valves). During interviews, operators stated that they had been trained in the simulator to send local operators to close MSR valves as a contingency action. However, this action is not listed in the Foldout A procedure and no additional or alternate action that could be performed from the control boards, such as closing the MSIVs, is specified. Additionally, Path-1 Turbine Tripped does not contain additional steps that operators might be reasonably expected to take in order to accomplish the intent of the step, such as closing the MSIVs, in the event that the specified contingency actions of manually tripping the turbine and running back the turbine are not successful. The team also identified an inconsistency between the Path-1 Basis Document and the licensees emergency operating procedure users guide regarding the immediate operator action of SI Initiation. Path-1 EOP does not explicitly list parameters or conditions to be checked in order to determine if a safety injection is required (requiring both the operator performing the immediate action and the CRS who is reading the procedure to rely on their knowledge). However, the Path-1 Basis Document provides an interpretation of this step that states, in part, that a safety injection is required if RCS inventory is decreasing in an uncontrolled manner and exceeding all available makeup flow. OMM-022, Emergency Operating Procedures Users Guide Section 8.3.1, Item 10, lists parameters and values that operators are expected to check when performing this immediate action step. The team noted that this step in OMM-022 does not specify checking RCS parameters directly related to RCS inventory, such as pressurizer level, as described in the Path-1 basis document. The team reviewed plant data from the first event and determined that pressurizer level decreased off-scale. Based on interviews, the team also determined that operators did not recognize the magnitude and rate of the pressurizer level decrease caused by the ongoing RCS cool down. Consequently, the team identified the need for additional NRC review to determine the adequacy of OMM-022 with respect to the immediate operator action of checking whether a safety injection is required. This review will determine whether the inconsistency between the Emergency Operating Procedures Users Guide and the Path-1 Basis Document is a performance deficiency. An Unresolved Item will be opened pending completion of this review. The URI is identified as 05000216/2010009- 06, Adequacy of Emergency Operating Procedure Background Documents.
05000261/FIN-2010009-07	2010Q2	Robinson	Loss of Seal Water Results in Failure of the A Main Condeser Vacuum Pump	The team observed that procedure GP-004 Post Trip Stabilization contained a step to reset the generator lockout relays but did not contain steps, cautions, or notes that prompt operators to ensure the inputs are clear prior to attempting a reset. Although AOP-024, Loss of Instrument Buses was not used, and was not required to be used per the licensees procedure use guidelines during this event, the team noted that the procedure does not address the effect of a loss of an instrument bus on the main steam flow channels that input into the Main Steam Line Isolation Signal. Additionally, AOP-024 does not address the loss of CCW flow to the RCP thermal barrier heat exchangers (FCV-626 closure). The team reviewed the circumstances which resulted in the fire in and subsequent failure of the A Main Condenser Vacuum Pump. The pump failed because seal water to the pump, which is supplied by demineralized water, was lost for approximately three and a half hours prior to the pump failure. The loss of power following the first fire caused the loss of demineralized water. The Main Condenser Vacuum Pump establishes and maintains condenser vacuum to provide a heat sink used for decay heat removal following a reactor trip. The team observed that the licensee does not have a procedure to address loss of seal water makeup to the main condenser vacuum pumps. Use of such a procedure could have prevented the fire and associated damage to this equipment. As a result of this observation, the team identified the need for additional NRC review to determine if procedures should have been available to address a sustained loss of seal water makeup to the main condenser vacuum pumps. Additional review by the NRC will be needed to determine whether the lack of a procedure for loss of seal water to the main condenser vacuum pumps is a performance deficiency. An Unresolved Item will be opened pending completion of this review. The URI is identified as 05000261/2010009-07, Loss of Seal Water Results in Failure of the A Main Condenser Vacuum Pump.
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.
05000261/FIN-2010009-11	2010Q2	Robinson	FCV 626, RCP Thermal Barrier Outlet Isolations CCW Valve, Unexpected Closure	Valve FCV-626 is located in the combined CCW return from the three RCP thermal barrier heat exchangers. In its normal open position it allows CCW flow to pass through the thermal barrier heat exchangers, providing backup cooling to the RCP seals in the event of a loss of the primary cooling flow (seal injection) from the charging pumps. There are two close functions for FCV-626: 1) closes on high flow in the return line which is indicative of a rupture of a thermal barrier heat exchanger (RCS to CCW system leak) and 2) closes in response to a Phase B containment isolation signal. The valve has no automatic opening functions. The valve closed when power to safety-related 480 volt Bus E-2 was transferred to the emergency diesel generator. The valve remained closed for approximately 39 minutes before the operators recognized the condition, reopened FCV-626, and restored CCW cooling to the RCP thermal barrier heat exchangers. Plant staff knew that FCV-626, a motor operated valve, was powered from Bus E-2 via MCC 6. However, plant staff, including operators, was unaware that FCV-626 would close on a momentary loss of power. Additionally, the simulator was modeled such that FCV-626 remained open when power to Bus E-2 was momentarily interrupted. The high flow closure function of FCV-626 is accomplished using flow orifice FE-626, which is located in the thermal barrier return line, and provides flow switch FIC-626 with a hydraulic input to operate high and low flow contacts. When the high flow contact opens, relay FIC-626X is de-energized and closes a contact in the closing circuit for the motor operator of FCV-626, thereby closing FCV-626. Plant procedure EDP-008, Instrument Buses, incorrectly indicated that the power source for the flow switch FIC-626 control circuit was from Instrument Bus 1. The power for the FIC-626 control circuit is from Instrument Bus 4. Instrument Bus 4 is fed from MCC-6, which also feeds motor operated valve FCV-626. When Bus E-2 transferred to the EDG, both valve FCV-626 and relay FIC-626X lost power for approximately 10 seconds. During this time interval, relay FIC-626X repositioned to its de-energized state, which closed a contact in the close circuit of valve FCV-626. When Bus E-2 reenergized, valve FCV-626 immediately began to close, which sealed in contacts to completely close the valve. The close circuit was sealed in before relay FIC-626X reset to its energized state. The team concluded that the most likely cause of the time delay for the relay to reset was a constant voltage transformer located between the relay and MCC-6. The safety significance of inadvertent shutoff of RCP thermal barrier cooling water is discussed in Section 1.1 of this report. The team reviewed historical data associated with the control circuit for valve FCV-626 and determined the licensee had at least two potential opportunities to discover the behavior of FCV-626 on a loss of power. The first opportunity was in 2005 while implementing Engineering Change (EC) 59456. While performing the EC, workers encountered wiring issues as documented in NCR168221. The licensee subsequently determined that flow switch FIC-626, which was previously thought to be powered from Instrument Bus 1, required no power to operate. As part of that investigation, it was noted that relay FIC-626X was powered from Instrument Bus 4. Wiring discrepancies existed in some of the associated drawings, but were either not noted or not pursued. 27 Enclosure 1 Additionally, the licensee did not update EDP-008, which continued to show Instrument Bus 1 Breaker 16 as the power source for the flow switch FIC-626 control circuit. The licensee has written NCR 391995 to correct these deficiencies. The second opportunity occurred in 2008 during the performance of OST-163, Safety Injection Test and Emergency Diesel Generator Auto Start on Loss of Power and Safety Injection (refueling). As part of the test, 480V safety-related Bus E-2 was transferred to the B EDG. Data recovered by the licensee indicated that FCV-626 closed at approximately the same time the B EDG re-energized Bus E-2. However, during the test, CCW system flow, which was being provided by the opposite train of power, was stable and RCPs were not running. Thus sufficient information was available to recognize that flow perturbations were not the cause for FCV-626 closing. About two hours later, the valve was reopened. The licensee either did not identify or did not pursue the unexpected behavior of FCV-626. The ERT entered the problems described in this section into the corrective action system. One corrective action will clarify the drawings associated with the control circuitry of FCV-626 and make some minor corrections to current drawings. Another corrective action will implement a modification to prevent inadvertent closure of valve FCV-626 for a momentary loss of power. The licensee stated the modification would be implemented prior to restart of the plant from the refueling outage. Additional review by the NRC will be needed to determine whether the design of FCV- 626, which caused the valve to close during a momentary loss of power, represents a performance deficiency. An Unresolved Item will be opened pending completion of this review. This issue is identified as URI 05000261/2010009-11, FCV 626, RCP Thermal Barrier Outlet Isolation CCW Valve, Unexpected Closure. In order to better understand the reason FCV-626 closed during a momentary loss of power, the team reviewed the licensing bases for the CCW system, including FCV-626. The team reviewed correspondence between the licensee and the NRC regarding NUREG 0737, Clarification of TMI Action Plan Requirements, Item II.K.3.25, Power on Pump Seals. This TMI item required the licensee to determine the consequences of a loss of RCP cooling due to a loss of offsite power lasting two hours. In their correspondence, the licensee stated that no modifications were necessary because the CCW system is still operable during a loss of offsite power (powered from the emergency buses) and provides flow to the RCP thermal barrier heat exchangers. They also stated that the B and C CCW pumps are automatically (requiring no operator action) started by a station blackout signal during a loss of offsite power event. Additional review by the NRC will be needed to determine if the behavior of RCP seal cooling following a loss of offsite power event is consistent with the description provided by the licensee in NUREG 0737 correspondence and if any differences represent a violation. An Unresolved Item will be opened pending completion of this review. The issue is identified as URI 05000261/2010009-12, NUREG 0737 Response From Licensee to the NRC Describing the Behavior of RCP Seal Cooling Following a Loss of Offsite Power Event.
05000261/FIN-2010009-12	2010Q2	Robinson	NUREG 0737 Response From Licensee to the NRC Describing the Behavior of RCP Seal Cooling Following a Loss of Offsite Power Event	Valve FCV-626 is located in the combined CCW return from the three RCP thermal barrier heat exchangers. In its normal open position it allows CCW flow to pass through the thermal barrier heat exchangers, providing backup cooling to the RCP seals in the event of a loss of the primary cooling flow (seal injection) from the charging pumps. There are two close functions for FCV-626: 1) closes on high flow in the return line which is indicative of a rupture of a thermal barrier heat exchanger (RCS to CCW system leak) and 2) closes in response to a Phase B containment isolation signal. The valve has no automatic opening functions. The valve closed when power to safety-related 480 volt Bus E-2 was transferred to the emergency diesel generator. The valve remained closed for approximately 39 minutes before the operators recognized the condition, reopened FCV-626, and restored CCW cooling to the RCP thermal barrier heat exchangers. Plant staff knew that FCV-626, a motor operated valve, was powered from Bus E-2 via MCC 6. However, plant staff, including operators, was unaware that FCV-626 would close on a momentary loss of power. Additionally, the simulator was modeled such that FCV-626 remained open when power to Bus E-2 was momentarily interrupted. The high flow closure function of FCV-626 is accomplished using flow orifice FE-626, which is located in the thermal barrier return line, and provides flow switch FIC-626 with a hydraulic input to operate high and low flow contacts. When the high flow contact opens, relay FIC-626X is de-energized and closes a contact in the closing circuit for the motor operator of FCV-626, thereby closing FCV-626. Plant procedure EDP-008, Instrument Buses, incorrectly indicated that the power source for the flow switch FIC-626 control circuit was from Instrument Bus 1. The power for the FIC-626 control circuit is from Instrument Bus 4. Instrument Bus 4 is fed from MCC-6, which also feeds motor operated valve FCV-626. When Bus E-2 transferred to the EDG, both valve FCV-626 and relay FIC-626X lost power for approximately 10 seconds. During this time interval, relay FIC-626X repositioned to its de-energized state, which closed a contact in the close circuit of valve FCV-626. When Bus E-2 reenergized, valve FCV-626 immediately began to close, which sealed in contacts to completely close the valve. The close circuit was sealed in before relay FIC-626X reset to its energized state. The team concluded that the most likely cause of the time delay for the relay to reset was a constant voltage transformer located between the relay and MCC-6. The safety significance of inadvertent shutoff of RCP thermal barrier cooling water is discussed in Section 1.1 of this report. The team reviewed historical data associated with the control circuit for valve FCV-626 and determined the licensee had at least two potential opportunities to discover the behavior of FCV-626 on a loss of power. The first opportunity was in 2005 while implementing Engineering Change (EC) 59456. While performing the EC, workers encountered wiring issues as documented in NCR168221. The licensee subsequently determined that flow switch FIC-626, which was previously thought to be powered from Instrument Bus 1, required no power to operate. As part of that investigation, it was noted that relay FIC-626X was powered from Instrument Bus 4. Wiring discrepancies existed in some of the associated drawings, but were either not noted or not pursued. 27 Enclosure 1 Additionally, the licensee did not update EDP-008, which continued to show Instrument Bus 1 Breaker 16 as the power source for the flow switch FIC-626 control circuit. The licensee has written NCR 391995 to correct these deficiencies. The second opportunity occurred in 2008 during the performance of OST-163, Safety Injection Test and Emergency Diesel Generator Auto Start on Loss of Power and Safety Injection (refueling). As part of the test, 480V safety-related Bus E-2 was transferred to the B EDG. Data recovered by the licensee indicated that FCV-626 closed at approximately the same time the B EDG re-energized Bus E-2. However, during the test, CCW system flow, which was being provided by the opposite train of power, was stable and RCPs were not running. Thus sufficient information was available to recognize that flow perturbations were not the cause for FCV-626 closing. About two hours later, the valve was reopened. The licensee either did not identify or did not pursue the unexpected behavior of FCV-626. The ERT entered the problems described in this section into the corrective action system. One corrective action will clarify the drawings associated with the control circuitry of FCV-626 and make some minor corrections to current drawings. Another corrective action will implement a modification to prevent inadvertent closure of valve FCV-626 for a momentary loss of power. The licensee stated the modification would be implemented prior to restart of the plant from the refueling outage. Additional review by the NRC will be needed to determine whether the design of FCV- 626, which caused the valve to close during a momentary loss of power, represents a performance deficiency. An Unresolved Item will be opened pending completion of this review. This issue is identified as URI 05000261/2010009-11, FCV 626, RCP Thermal Barrier Outlet Isolation CCW Valve, Unexpected Closure. In order to better understand the reason FCV-626 closed during a momentary loss of power, the team reviewed the licensing bases for the CCW system, including FCV-626. The team reviewed correspondence between the licensee and the NRC regarding NUREG 0737, Clarification of TMI Action Plan Requirements, Item II.K.3.25, Power on Pump Seals. This TMI item required the licensee to determine the consequences of a loss of RCP cooling due to a loss of offsite power lasting two hours. In their correspondence, the licensee stated that no modifications were necessary because the CCW system is still operable during a loss of offsite power (powered from the emergency buses) and provides flow to the RCP thermal barrier heat exchangers. They also stated that the B and C CCW pumps are automatically (requiring no operator action) started by a station blackout signal during a loss of offsite power event. Additional review by the NRC will be needed to determine if the behavior of RCP seal cooling following a loss of offsite power event is consistent with the description provided by the licensee in NUREG 0737 correspondence and if any differences represent a violation. An Unresolved Item will be opened pending completion of this review. The issue is identified as URI 05000261/2010009-12, NUREG 0737 Response From Licensee to the NRC Describing the Behavior of RCP Seal Cooling Following a Loss of Offsite Power Event.
05000261/FIN-2010009-13	2010Q2	Robinson	Dedicated Shutdown Diesel Generator Failed to Start Due to Low Starting Air Pressure	The team reviewed the circumstances which resulted in a failure of the DSDG to start. The team reviewed completed procedures, log entries, system drawings and performed a system walkdown. At 18:52 on March 28, the DS bus was automatically de-energized, as designed, due to undervoltage on 4 kV Bus 3. As a result, the DSDG support equipment, such as the starting air system compressor and battery charger, lost power. Based in part on adequate starting air pressure, the licensee considered the DSDG available for the purpose of assessing on-line risk. The log reading normal minimum value for starting air pressure is 165 psig and operators were monitoring this parameter twice per day. At 14:41 on March 31 the licensee attempted to start the DSDG and re-energize the DS bus to maintain adequate DSDG support parameters such as starting air pressure and battery voltage. Starting air pressure had decreased to 100 psig and the DSDG did not start. The licensee successfully started the DSDG on April 1 at 13:40 by pressurizing the DSDG starting air receiver tank using high pressure air bottles. Both the E-1 and E-2 safety buses were energized during this time with Bus E-1 powered from off-site power and Bus E-2 supplied from EDG B. The licensee entered Condition Reports 390954 and 390958 into their corrective action program. Additional review by the NRC will be required to determine if the DSDG was available when credited in the licensees risk assessment during the plant cooldown to Mode 4. This review will also determine whether this issue represents a performance deficiency. An Unresolved Item will be opened pending completion of this review. The issue will be identified as URI 05000261/2010009-13, Dedicated Shutdown Diesel Generator Failed to Start Due to Low Starting Air Pressure.
05000261/FIN-2010009-14	2010Q2	Robinson	Unexpected Loss of Instrument Bus 3 for Two Minutes	The team reviewed the circumstances which resulted in an inadvertent de-energization of Instrument Bus 3. The team reviewed completed procedures, log entries, and system drawings. The team also interviewed personnel and performed a system walkdown. At 18:52 on March 28 the B battery charger de-energized due to loss of power to Bus E-2. Per Path-1, control room operators subsequently dispatched an Auxiliary Operator (AO) to restore the B battery charger. As the AO entered the battery room he made inadvertent contact with the handle for the B Inverter Supply Breaker 72/MCC-B (1K). The contact resulted in breaking the handle off of the breaker. Based on the timeframe when the AO entered the battery room and the time when Instrument Bus 3 was unexpectedly loss, the licensees ERT concluded the contact with the breaker caused the loss of Instrument Bus 3. The Auxiliary Operator recognized the damage to the breaker handle and continued to complete the restoration the B battery charger. The B battery charger was restored at 19:31. Upon exiting the battery room the AO verified the B inverter was operating correctly and reported the damage to the breaker handle. A review of plant data indicated Instrument Bus 3 was de-energized at 19:25 and reenergized at 19:27. The loss of Instrument Bus 3 power deenergized the High Steam Flow bistables in the Engineered Safety Features system. This condition, coincident with an RCS Low Tavg signal due to the RCS cooldown, generated a Main Steam Line Isolation signal, automatically closing all MSIVs and terminating the RCS cooldown. Based on interviews with the AO, no actions were performed to reset or reclose the B Inverter Supply Breaker. The licensee generated Work Order 01735191 to repair the broken breaker handle. The licensee performed troubleshooting activities to determine the cause of the two-minute interruption in instrument bus power, but was unable to detect any problems. The licensee was continuing to perform troubleshooting at the time this report was written. The licensee entered Condition Report 390070 into their corrective action program. Additional review by the NRC will be needed to assess the adequacy of the licensee troubleshooting efforts and evaluate any problems that may be identified. This review will also determine whether any performance deficiencies exist. An Unresolved Item will be opened pending completion of this review. The issue will be identified as URI 05000261/2010009-14, Unexpected Loss of Instrument Bus 3 for Two Minutes.
05000261/FIN-2010009-01	2010Q2	Robinson	Monitoring of Plant Parameters and Alarms	The team conducted an independent review of control room activities to determine if licensee staff responded properly during the events. With respect to operator awareness and decision making, the team was specifically focused on the effectiveness of control board monitoring, communications, technical decision making, and work practices of the operating crew. With respect to command and control, the team was specifically focused on actions taken by the control room leadership in managing the operating crews response to the event. The team performed the following activities in order to understand and/or confirm the control room operating teams actions to diagnose the event and implement corrective actions: Conducted interviews with control room operations personnel on shift during the event. Reviewed procedures, narrative logs, event recorder data, system drawings, and plant computer data. Observed a simulated plant response to this event as demonstrated on the plant reference simulator. Reviewed the crews implementation of emergency, abnormal, and alarm procedures as well as Technical Specifications. Reviewed Operations administrative procedures concerning shift manning and procedure use and coordination. Reviewed Operations procedures in use at the time of the second fire. The team determined that operators exhibited weaknesses in fundamental operator competencies when responding to the event. Specifically, the team determined that the operating crew did not identify important off-normal parameters and alarms in a timely manner, resulting in a failure to recognize an uncontrolled RCS cooldown and a potential challenge to RCP seal cooling. Additionally, the team determined that crew supervision did not exercise effective oversight of plant status, crew performance, or site resources. Through a review of plant data, the team determined that the crews response to the first event was not effective in stabilizing the plant. Through interviews and review of plant data, the team determined that the crew did not recognize the magnitude of the RCS cool down caused by an on-going steam demand. The RCS cool down rate exceeded the limit of 100o/hr in any one hour period as specified in Technical Specification (TS) 3.4.3, RCS Pressure and Temperature (P/T) Limits. The fact that the RCS cooldown rate exceeded the limiting value specified in TS 3.4.3, and the requirement to evaluate the actions contained in TS 3.4.3, was not recognized by the crew at any time during or after the cooldown. Based on interviews, the Reactor Operator (RO) and Control Room Supervisor (CRS) assessed the cool down rate as being consistent with what was experienced during simulator training for an RCP trip followed by a reactor trip. The RCS cool down continued until Instrument Bus 3 was inadvertently de-energized (approximately 33 minutes after the start of the first event), which caused the MSIVs to close, isolating the steam generators from the steam header. Based on the sequence of events, a review of plant data, and operator interviews, the team concluded that the crew did not recognize that VCT level was decreasing, a low VCT level alarm had annunciated, and automatic swapover of the charging pump suction from the VCT to the RWST failed to occur, until indicated level in the VCT had decreased to approximately 2-3 inches and charging flow had degraded. Once the crew identified this condition, the RO attempted to manually align the suction of the charging pumps to the RWST but made an error when performing the alignment. The error left the suction of the charging pumps aligned to the VCT. The Shift Technical Advisor (STA) determined the alignment was incorrect and the RO corrected the error. The crew did not reference APP-003-E3, VCT HI/LO LVL, which provided direction to manually transfer the charging pump suction to the RWST. RCP seal cooling was maintained because the crew reopened FCV-626 to restore CCW cooling to the RCP thermal barrier heat exchanger approximately 6 minutes before depletion of the VCT. However, high pump bearing temperature alarms were received on all three RCPs. The high temperature alarms subsequently cleared after operators reopened FCV-626. Based on operator interviews, the team concluded that, following implementation of Emergency Operating Procedures (EOPs), the operators did not complete a satisfactory review and evaluation of alarm conditions prior to the second event. Instead, the operating crew entered GP-004, Post Trip Stabilization, and attempted to reset the generator lockout relay without using the information in the Annunciator Panel Procedures (APPs) to completely and accurately assess abnormal electric plant status. GP-004 is a normal operating procedure and is written with the assumption that the plant is in a normal (undamaged) configuration. The crew was not aware that a sudden pressure fault signal from the UAT was still applied to the generator lockout circuit logic, as indicated by a locked in UAT fault trip alarm (APP-009-B6, AUX TRANSF FAULT TRIP). The attempted reset reenergized Bus 4 and caused a fault at breaker 52/24, initiating the sequence for the second fire. The team concluded that if the crew had performed a thorough control board walkdown, additional electric plant APPs and/or AOPs could have been identified and implemented before exiting to a normal operating procedure (GP-004). Additional review by the NRC will be required to determine if the licensees programs resulted in untimely identification and investigation of abnormal plant parameters and unexpected main control room alarms. This review will also determine whether the crews monitoring of plant parameters and alarms, and use of associated procedures, represents a performance deficiency. An Unresolved Item will be opened pending completion of this review. The URI is identified as 05000261/2010009-01, Monitoring of Plant Parameters and Alarms. Additionally, further review by the NRC will be required to determine if the RCS cooldown rate exceeding the limiting value specified in TS 3.4.3 represents a performance deficiency. An Unresolved Item will be opened pending completion of this review. The URI is identified as 05000261/2010009-02, RCS Cooldown Rate Exceeds Technical Specification 3.4.3 Limit.
05000261/FIN-2010009-02	2010Q2	Robinson	RCS Cooldown Rate Exceeds Technical Specification 3.4.3 limit	Through a review of plant data, the team determined that the crews response to the first event was not effective in stabilizing the plant. Through interviews and review of plant data, the team determined that the crew did not recognize the magnitude of the RCS cool down caused by an on-going steam demand. The RCS cool down rate exceeded the limit of 100o/hr in any one hour period as specified in Technical Specification (TS) 3.4.3, RCS Pressure and Temperature (P/T) Limits. The fact that the RCS cooldown rate exceeded the limiting value specified in TS 3.4.3, and the requirement to evaluate the actions contained in TS 3.4.3, was not recognized by the crew at any time during or after the cooldown. Based on interviews, the Reactor Operator (RO) and Control Room Supervisor (CRS) assessed the cool down rate as being consistent with what was experienced during simulator training for an RCP trip followed by a reactor trip. The RCS cool down continued until Instrument Bus 3 was inadvertently de-energized (approximately 33 minutes after the start of the first event), which caused the MSIVs to close, isolating the steam generators from the steam header. Based on the sequence of events, a review of plant data, and operator interviews, the team concluded that the crew did not recognize that VCT level was decreasing, a low VCT level alarm had annunciated, and automatic swapover of the charging pump suction from the VCT to the RWST failed to occur, until indicated level in the VCT had decreased to approximately 2-3 inches and charging flow had degraded. Once the crew identified this condition, the RO attempted to manually align the suction of the charging pumps to the RWST but made an error when performing the alignment. The error left the suction of the charging pumps aligned to the VCT. The Shift Technical Advisor (STA) determined the alignment was incorrect and the RO corrected the error. The crew did not reference APP-003-E3, VCT HI/LO LVL, which provided direction to manually transfer the charging pump suction to the RWST. RCP seal cooling was maintained because the crew reopened FCV-626 to restore CCW cooling to the RCP thermal barrier heat exchanger approximately 6 minutes before depletion of the VCT. However, high pump bearing temperature alarms were received on all three RCPs. The high temperature alarms subsequently cleared after operators reopened FCV-626. Based on operator interviews, the team concluded that, following implementation of Emergency Operating Procedures (EOPs), the operators did not complete a satisfactory review and evaluation of alarm conditions prior to the second event. Instead, the operating crew entered GP-004, Post Trip Stabilization, and attempted to reset the generator lockout relay without using the information in the Annunciator Panel Procedures (APPs) to completely and accurately assess abnormal electric plant status. GP-004 is a normal operating procedure and is written with the assumption that the plant is in a normal (undamaged) configuration. The crew was not aware that a sudden pressure fault signal from the UAT was still applied to the generator lockout circuit logic, as indicated by a locked in UAT fault trip alarm (APP-009-B6, AUX TRANSF FAULT TRIP). The attempted reset reenergized Bus 4 and caused a fault at breaker 52/24, initiating the sequence for the second fire. The team concluded that if the crew had performed a thorough control board walkdown, additional electric plant APPs and/or AOPs could have been identified and implemented before exiting to a normal operating procedure (GP-004). Additional review by the NRC will be required to determine if the licensees programs resulted in untimely identification and investigation of abnormal plant parameters and unexpected main control room alarms. This review will also determine whether the crews monitoring of plant parameters and alarms, and use of associated procedures, represents a performance deficiency. An Unresolved Item will be opened pending completion of this review. The URI is identified as 05000261/2010009-01, Monitoring of Plant Parameters and Alarms. Additionally, further review by the NRC will be required to determine if the RCS cooldown rate exceeding the limiting value specified in TS 3.4.3 represents a performance deficiency. An Unresolved Item will be opened pending completion of this review. The URI is identified as 05000261/2010009-02, RCS Cooldown Rate Exceeds Technical Specification 3.4.3 Limit.
05000261/FIN-2010009-03	2010Q2	Robinson	Utilization of operators During Events Requiring Use of Concurrent Procedures	Through interviews, the team determined that the Balance of Plant (BOP) operator concurrently performed Abnormal Operating Procedure (AOP)-041, Response to Fire Event, during the first event. The team observed that AOP-041 contains numerous steps to coordinate on-site and off-site fire brigade response and notifications. The team determined that having a licensed operator perform AOP-041, concurrent with the CRS and RO performing emergency operating procedures, is a licensee expectation in accordance with OMM-022, Emergency Operating Users Guide. Through interviews, the team determined that because the BOP operator was performing AOP-041, he was unavailable to assist the control room team in recognizing and diagnosing off-normal events and conditions for approximately the first 30 minutes of the first event. During interviews, the two operators responsible for panel operation (the RO and CRS) consistently noted the unavailability of a third person (the BOP licensed operator) to perform independent panel checks. The team noted that during conditions of minimum manning, using the BOP operator to concurrently perform certain AOPs may hinder or prevent him or her from assisting the CRS and RO in stabilizing the plant during events that challenge the control room crew. Additional review by the NRC will be needed to determine if the licensees utilization of operators, during conditions of minimum control room manning, is adequate during complex events. This review will also determine if this issue represents a performance deficiency. An Unresolved Item will be opened pending completion of this review. The issue will be identified as URI 05000261/2010009-03, Utilization of Operators During Events Requiring Use of Concurrent Procedures.
05000261/FIN-2010008-01	2010Q1	Robinson	Aging Management Program for exterior surface of EOF/TSC Main Storage Tank	The inspectors identified an Unresolved Item related to the Emergency Operations Facility/Technical Support Center (EOF/TSC) Diesel Generator Main Storage Tank (buried diesel fuel oil tank), for which additional information and discussion was needed to determine if a performance deficiency existed, if the performance deficiency was more than minor, or if the issue of concern constituted a violation of NRC requirements. The inspectors noted that Table 2.3-25 of the LRA lists the components in the Fuel Oil System that require aging management review. This table shows that the results of the AMR for the EOF/TSC Main Storage Tank are documented in Table 3.3-1 and Table 3.3-2 of the LRA. Table 3.3-1 specifies that aging management for the diesel fuel oil tanks made of carbon steel in the diesel fuel oil system and the EDG system will be implemented through the Fuel Oil Chemistry Program. Table 3.3-2 specifies that the EOF/TSC Main Storage Tank is a buried tank made of fiberglass reinforced polyester. The licensee stated in this table that no aging effects or AMP applies to this tank. Additionally, section B.3.12 of the LRA, Buried Piping and Tanks Inspection Program states that this AMP does not contain buried tanks. In RAI B.3.12-1, the NRR staff requested confirmation that no buried tanks were covered under the Buried Piping and Tanks Inspection Program. In its response to this RAI dated April 28, 2003, the licensee stated that the program does not contain buried tanks. During the review of AMR documents for LR commitments, the inspectors identified that the EOF/TSC Main Storage Tank is made of carbon steel covered with 1/8 nominal exterior coating of fiberglass reinforced polyester. The inspectors noted that the description of the tank in Table 3.3-2 did not include carbon steel. The inspectors questioned the licensee with regard to the basis for excluding this buried tank from the scope of the Buried Piping and Tanks Inspection Program. According to the licensee, the combination of tank material and environment (i.e. buried carbon steel tank covered with fiberglass reinforced polyester) is not specifically addressed in Table VII.H1 of the GALL Report and therefore the licensee treated this tank as a component that is different from the GALL Report. The inspection team remained concerned whether the exclusion of the EOF/TSC Main Storage Tank from the Buried Piping and Tanks Inspection Program was appropriate and whether the AMP selected by the licensee to manage aging on the tanks surfaces was adequate. This issue required further review. Therefore, this issue will be tracked as an unresolved item (URI 5000261/2010008-01)
05000261/FIN-2010002-01	2010Q1	Robinson	Inaccurate Drawings Result I Loss of RWST Level Indication Due to Freezing	A self-revealing non-cited violation of Technical Specification 5.4.1, Procedures, was identified in that the licensee used inaccurate drawings to hang clearances on freeze protection circuits which resulted in the Refueling Water Storage Tank (RWST) level instrument lines freezing. The licensee failed to properly translate the design of the freeze protection circuits to the drawings used in the clearances, causing the RWST level sensing line freeze protection to be unavailable. The licensee removed the clearance, re-energized the freeze protection and level indications were restored. The licensee entered the drawing discrepancy issue into the corrective action program as AR 374561 The disabling of the RWST level instrument freeze protection during the RHR pump work is a performance deficiency. The finding is more than minor because it affected the mitigating systems cornerstone objective to ensure the availability, reliability and capability of systems that respond to initiating events. Specifically, the RWST level instrument line freezing caused the required post accident instrumentation of the RWST to be inoperable. Using Appendix A of the Significance Process (SDP) described in IMC 0609, Mitigating System Cornerstone, this finding was determined to have very low safety significance (Green) because no loss of operability or functionality of the RWST resulted from the level sensing line freezing. There is no cross-cutting aspect of this NCV since the incorrect drawing that resulted in the inaccurate clearance was last revised in 1986 and is not indicative of current licensee performance.
05000261/FIN-2010002-02	2010Q1	Robinson	A Emergency Diesel Generator Fuel Oil Transfer Pump Power Supply Cable Subjected to Continuous Submersion in Water Design Deficiency	The inspectors identified a NCV of 10 CFR Part 50, Appendix B, Criterion III, Design Control, in that the licensee failed to maintain a safety-related cable in an environment for which it was designed. Specifically, the A Emergency Diesel (EDG) Fuel Oil Transfer Pump power supply cable was exposed to continuous submersion in water. The licensee removed the accumulated water from the hand hole, resealed, and reinstalled the hand hole cover. The licensee entered the issue into the corrective action program as AR 370343. Failure to maintain a safety related cable in an environment for which it was designed is a performance deficiency. The finding is more than minor in accordance with IMC 0612, Appendix B (Block 9, Figure 2), Issue Screening, because if left uncorrected, the performance deficiency has the potential to lead to a more significant safety concern. Specifically, subjecting the A EDG fuel oil transfer pump cable to continuous submersion could, over time degrade the cable and result in failure. 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 cause of the finding was directly related to the problem evaluation 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 NRC Generic Letter 2007-01 Inaccessible or Underground Power Cable Failures that Disable Accident Mitigation Systems or Cause Plant Transients (P.1 (c)
05000445/FIN-2009005-01	2009Q4	Comanche Peak	Inadequate Procedure for Environmentally Qualified Actuator Refurbishment	The inspectors identified a noncited violation of 10 CFR Part 50, Appendix B, Criterion III, for the failure of the licensee to translate environmental qualification requirements for motor operated valve and damper actuators into procedures. Specifically, actuator refurbishment procedures directed the removal of conduit plugs, drain plugs, and T-drains, but did not require them to be re-installed in the correct configuration. As a result, multiple actuators were not in their specified condition for environmental qualification. After evaluation, the licensee determined that the actuators were still environmentally qualified in the as-found configuration. The licensee entered the finding into the corrective action program as Condition Report CR-2009-000848. The finding was more than minor because it was associated with the containment configuration control attribute of the barrier integrity cornerstone and adversely affected the cornerstone objective, in that, the licensees procedure for actuator refurbishment did not provide reasonable assurance that actuators would continue to be environmentally qualified in order to protect the public from radionuclide releases caused by accidents or events. Using NRC Manual Chapter 0609, Attachment 4, Phase 1 - Initial Screening and Characterization of Findings, the finding was determined to be of very low safety significance because the finding did not represent an actual open pathway in the physical integrity of reactor containment. The finding has a human performance cross cutting aspect associated with resources because the licensee failed to maintain complete and accurate procedures (H.2c
05000445/FIN-2009005-04	2009Q4	Comanche Peak	Failure to Barricade and Post a High Radiation Area	The inspectors reviewed a self-revealing noncited violation of Technical Specification 5.7.1.a for failure to maintain a high radiation area barricaded and conspicuously posted. The lower valve gallery on the 832-foot elevation of the auxiliary building had been de-posted from a locked high radiation area to radiation area after a resin transfer and flush operation. Radiation protection had mistakenly determined, by a partial radiation survey, that the entire lower valve gallery was a radiation area. Consequently, two workers received unexpected electronic dose rate alarms because the workers entered a high radiation area without knowledge that dose rates measured 900 millirem per hour. The licensee revised Procedure RPI-624, Resin Transfer Job Coverage, to provide clear instructions requiring that radiation surveys of the whole system after resin transfers and flushes are completed. The licensee entered the finding into the corrective action program as Condition Report CR-2009-002876. The failure to barricade and post a high radiation area is a performance deficiency. The finding was more than minor because it was associated with the occupational radiation safety cornerstone attribute (exposure control) of program and process and affected the cornerstone objective, in that, the failure to properly control a high radiation area had the potential to increase personnel dose. Using the occupational radiation safety significance determination process, the inspectors determined the finding to have very low safety significance because: (1) it was not associated with as low as reasonably achievable (ALARA) planning or work controls, (2) there was no overexposure, (3) there was no substantial potential for an overexposure, and (4) the ability to assess dose was not compromised. The finding has a human performance crosscutting aspect associated with resources because the licensee did not ensure that the procedure was complete and accurate (H.2c
05000445/FIN-2009005-05	2009Q4	Comanche Peak	Failure to Report as Required by 10 CFR 26.27	The inspectors identified a noncited violation of 10 CFR 26.27 for the failure of an individual to comply with the licensees fitness-for-duty requirements. The licensee implemented immediate compensatory measures for this deficiency by briefing the event and providing personnel with the implications of such an activity and by reviewing implementing procedures, policies, and training. The licensee entered the noncited violation into the corrective action program as Condition Report CR-2009-000104. The failure to comply with the licensees requirements affecting fitness-for-duty is a performance deficiency. This issue was dispositioned using traditional enforcement. In accordance with Section IV.A.4 of the NRC Enforcement Policy, this issue is considered a Severity Level IV violatio
05000261/FIN-2009005-02	2009Q4	Robinson	Failure to Identify Oil Leakage on a Operating Charging Pump	The inspectors identified a Green finding for the licensees failure to identify an oil leak on the A charging pump. This failure was determined to be a performance deficiency with respect to licensee procedure OMM-001-11, Logkeeping, which requires oil leakage be identified and abnormal conditions reported to shift management. The licensee responded by stopping the A charging pump to verify proper oil level. An addition of 6.5 quarts was required to restore the oil level to normal. Additionally, to maintain operability, the licensee established a compensatory action to stop the A charging pump every three days to verify oil level until the oil leak was repaired. The licensee entered the issue into the corrective action program as AR 360876. The finding is more than minor because if left uncorrected the performance deficiency would have the potential to lead to a more significant safety concern. Given the history of continuous operation of the charging pumps for up to 37 days, if the identified oil leak remained uncorrected, a loss of lubrication failure of the A charging pump would occur. The charging pumps are technical specification required equipment and are used in the emergency operating procedures to mitigate the consequences of an event. This finding was determined to be green because no loss of operability or functionality of the A charging pump resulted from the identified oil leakage. The apparent cause of this finding was a failure to implement a procedural requirement to identify and communicate an oil leak to shift management. The inspectors determined no cross-cutting aspect was associated with this performance deficiency
05000261/FIN-2009005-01	2009Q4	Robinson	a EDG Fuel Transfer Pump Power Supply Cable Subberged in Water	The inspectors identified an unresolved item (URI) associated with the submergence of a safety-related cable. The inspectors identified approximately 3 inches of standing water in the manhole which contained the A EDG fuel oil transfer pump cabling. This item is unresolved pending further review and evaluation of the licensees environmental qualifications of the submerged 600V cable. During an inspection of the underground cable manhole/bunkers, the A EDG fuel oil transfer pump power supply cable was identified as being submerged in 3 inches of water. Additional inspection activities are needed to determine if the A EDG fuel oil transfer pump power supply cable is suitable for exposure to submersion in water. Pending the results of this additional inspection an Unresolved Item will be opened and designated as URI 05000261/2009005-01, A EDG Fuel Transfer Pump Power Supply Cable Submerged in Water
05000261/FIN-2009005-04	2009Q4	Robinson	Emergency Diesel Generator Inoperable in Excess of Technical Specifications Allowed Completion Time	A violation of TS 3.8.1. B was identified when the B Emergency Diesel Generator (EDG) was inoperable in excess of the TS allowed outage time. Enforcement discretion was exercised for this violation. No performance deficiency was identified. On April 20, 2009, the output breaker for the B EDG failed to close during the performance of planned surveillance testing. The licensee determined the cause of the breaker failure was due to the rotation of a cotter pin, used to retain a control relay lift linkage, during the previous breaker opening which prevented the lift linkage from returning to the normal position. The licensee entered the issue into the corrective action program as AR 331663 and initiated a root cause and extent of condition review. 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 March 28, 2009. As discussed in the licensees root cause report, the vendor had previously modified the breakers lifting link assembly. The drive screw/rolled pin that was originally used to retain the relays mechanical lift linkage was substituted with a cotter pin retaining component. This substitution created a design flaw because the cotter pin was susceptible to an unrecognized failure mechanism. The design flaw was reported by Westinghouse in accordance with 10 CFR 21 Reporting of Defects and Noncompliance, on May 28, 2009 (EN 45100). Because the cotter pin substitution was a vendor performed design change, the cause was not reasonably within the licensees ability to foresee and correct, therefore, no performance deficiency was identified. The inspector 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. However, 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 found an increase in core damage probability of 2.72 E-6 (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. Additionally, the licensee concluded that several response actions to recover the B EDG, such as the discovery of the misaligned relay lift linkage 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 are scheduled to be modified by May 15, 2010. Prior to implementation of this modification, satisfactory compensatory actions have been implemented which will ensure successful operation of the breaker.
05000261/FIN-2009005-03	2009Q4	Robinson	Licensee-Identified Violation	TS 3.3.2 required that PC-953A containment pressure switch channel be placed and maintained in the tripped condition. Contrary to this on June 29, 2009, during repair activities the channel was inadvertently removed from the tripped condition. The cause of the error was inadequate work instructions. The channel was restored to the tripped condition in approximately two minutes. This condition was documented in Condition Report 342793. This violation is of very low safety significance because the condition was promptly corrected in approximately 2 minutes and redundant channels were operable
05000445/FIN-2009005-02	2009Q4	Comanche Peak	Failure to Close the Containment Airlock Outer Door	The inspectors reviewed a self-revealing noncited violation of Technical Specification 5.4.1.a for the failure of maintenance personnel to follow procedural requirements for closing the containment personnel airlock outer door. As a result, the containment personnel outer door was left open for over an hour and the containment integrity function of the door was compromised. The licensee entered the finding into the corrective action program as Condition Report CR-2009-005275. The finding was more than minor because it was associated with the containment barrier performance attribute of the barrier integrity cornerstone and affects the cornerstone objective to provide reasonable assurance that physical barriers protect the public from radionuclide releases caused by events. Using NRC Manual Chapter 0609, Attachment 4, Phase 1 - Initial Screening and Characterization of Findings, the finding was determined to be of very low safety significance because the performance deficiency did not result in an actual open pathway in the physical integrity of the containment. The finding has a human performance crosscutting aspect associated with decision making because the licensee did not communicate the basis of the importance of the containment door providing an integrity function to the personnel operating the door (H.1c
05000445/FIN-2009005-03	2009Q4	Comanche Peak	Failure to Control Coolant System Pressure During Solid Plant Operations	The inspectors reviewed a self-revealing noncited violation of Technical Specification 5.4.1.a for the failure of operators to follow procedural requirements for maintaining reactor coolant system pressure. Specifically, a reactor operator adjusted charging flow during solid plant operations and failed to control the reactor coolant system pressure increase. As a result, a power operated relief valve lifted to provide low temperature overpressure protection of the reactor coolant system. The licensee entered the finding into the corrective action program as Condition Report CR-2009-005542. The finding was more than minor because it was associated with the human performance attribute of the initiating events cornerstone and affects the cornerstone objective to limit those events that upset plant stability and challenge critical safety functions during shutdown operations. Specifically, the inadvertent lifts of the power operated relief valves could lead to a loss of reactor coolant system inventory and pressure control. Using NRC Manual Chapter 0609, Appendix G, Attachment 1, Checklist 2, the finding was determined to be of very low safety significance because the licensee maintained adequate mitigation capability for the current plant state and the event was not characterized as a loss of control condition. The finding has a human performance crosscutting aspect associated with decision making because the licensee did not formally define the role of the reactor operator maintaining reactor coolant system pressure (H.1a
05000416/FIN-2009004-03	2009Q3	Grand Gulf	Licensee-Identified Violation	Title 10 CFR Part 50, Appendix B, Criterion V, Instructions, Procedures and Drawings, states, in part, that activities affecting quality shall be prescribed by documented procedures and shall be accomplished in accordance with those procedures. Contrary to this, no documented procedures were in place to ensure the operability of safety related ventilation systems that provides cooling for the standby service water pumphouses. On January 15, 2009, it was determined by the engineering staff that the ventilation flow rates for the safety related standby service water pump rooms were significantly degraded to almost half of normal flow rate for cooling and higher than normal flow rate for recirculation flow that is required during colder weather. The site determined that on August 20, 2009, the reason for the degraded flow was due to the ventilation screens being severely clogged and several dampers being broken in the open direction. It was determined by system engineering that no procedures or preventive maintenance schedules were in place to inspect, clean and restore degraded conditions in the ventilation system for the standby service water pump houses. This issue was documented in the licensees corrective action program as condition reportCR-GGN-2009-00199. This finding is of very low safety significance because although the ventilation flow rates were degraded operability of the standby service water pumps were maintained such that they could perform their safety function for their required mission time.
05000416/FIN-2009004-04	2009Q3	Grand Gulf	Licensee-Identified Violation	Title of 10 CFR Part 50 Appendix B, Criterion V, Instructions, Procedures and Drawings, states, in part, that activities affecting quality shall be prescribed by documented instructions and shall be accomplished in accordance with those instructions. Section 5.4(2) of Procedure EN-OP-104, Operability Determinations, Revision 3, required operability evaluations to provide a technical basis for each item in the detailed problem statements per Step 5 of Attachment 9.5 of the procedure. Contrary to the above, on August 21, 2009 plant engineers failed to provide a technical basis for the operability determination they performed by not considering external events such as earthquakes, high winds and tornados when determining operability of the standby services ventilation system which was in a degraded condition. Operations accepted the initial operability provided by engineering but the subsequent shift manager required the design engineering to perform new evaluation taking into account external events. The new operability determination was performed and determined that the standby service water system remained operable. This issue was documented in the licensees corrective action program as condition report CR-GGN-2009-04302. This finding was of very low safety significance since it did not result in a loss of operability of the standby service water system.
05000416/FIN-2009004-05	2009Q3	Grand Gulf	Licensee-Identified Violation	Title 10 of CFR Part 50, Appendix B, Criterion V, _Instructions, Procedures and Drawings,_ states, in part, that activities affecting quality shall be prescribed by documented procedures and shall be accomplished in accordance with those procedures. On September 16, 2009, plant operations management failed to implement section 6.1.1 of Procedure 02-1-S-17, Control of Limiting Conditions for Operation. The procedure states that the shift supervisor will initiate limiting conditions for operation whenever plant conditions warrant. Contrary to this, a limiting condition for operation was not entered prior to removing the inspection hatches on the standby gas treatment system. The reason for not entering the limiting conditions for operation action statement was due to maintenance supervisor assuming that worked started on September 14, 2009, that required entry into the limiting conditions for operation action statement, which operations entered that day, was never exited by operations when work was completed on September 14, 2009. Therefore, when work was recommenced on September 16, 2009, the maintenance department personnel never informed the control room. The maintenance personnel also failed to follow Procedure EN-AD-102, Procedure Adherence and Level of Use, Revision 5, Step 5.2.5 (3) that requires personnel to verify all prerequisites are still satisfied after stopping work for greater than shift. This issue was documented in the licensees corrective action program as condition report CR-GGN-2009-04754. This finding is of very low safety significance because it did not represent a degradation of the radiological barrier function provided for the control room, it did not represent a degradation of the barrier function of the control room against smoke or a toxic atmosphere, it did not represent an open pathway in containment, and did not impact the hydrogen igniters in containment.
05000416/FIN-2009004-06	2009Q3	Grand Gulf	Licensee-Identified Violation	Title 10 of the Code of Federal Regulations Part 74.19 requires, in part, that each licensee to keep records of inventory (including location and unique identity), transfer and disposal of all special nuclear material regardless of its origin or method of acquisition and to conduct an annual physical inventory of all special nuclear material in its possession. Contrary to the above, on July 22, 2009, during the performance of the2009 annual special nuclear material physical inventory, a discrepancy between the special nuclear material database and the physical inventory was determined. Specifically, the licensee failed to keep adequate records and inventory of a local power range monitor containing special nuclear material from 2005-2009. Inadequate records and inventory of the local power range monitor resulted in its shipment to a disposal facility in 2005. However, the inventory stated the location of the local power range monitor as the spent fuel pool. This error was discovered when a new engineer performed the 2009 physical inventory. This finding was documented in the licensees corrective action program as condition report CR-GGNS-2009-03729.
05000416/FIN-2009004-07	2009Q3	Grand Gulf	Licensee-Identified Violation	Title 10 of the Code of Federal Regulations, Part 50.47(b)(10) requires the licensee develop and have in place guidelines for the choice of protective actions during an emergency that are consistent with federal guidance. Contrary to this, prior to September 11, 2009, the licensee did not develop and have in place guidelines for the choice of protective actions during an emergency that were consistent with federal guidance. Specifically, the licensees guidelines for extending existing protective action recommendations into additional emergency planning zone sectors under conditions of changing wind vectors were not consistent with the guidance contained in EPA 400-R-92-001. Procedure 10-S-01-12, Radiological Assessment and Protective Action Recommendation, Revision 40, contains the licensees guidelines for extending existing protective action recommendations. The licensees practices result in unnecessary recommendations for protective actions in areas where valid dose projections show federal protective action guides are not exceeded, and may expose members of the public to unjustified risks. This issue is documented in the licensees corrective action program as condition reports CR-GGN-2009-3902 and CR-HQN-0757.This finding is of very low safety significance because it is not a risk significant planning standard functional failure or degraded function because the licensee would issue protective action recommendations to offsite authorities in accordance with federal guidance for all areas of the emergency planning zone where protective action guides are exceeded.
05000458/FIN-2009008-01	2009Q3	River Bend	Inadequate Operability Determinations for a Degraded Diesel Exhaust Pipe	The inspectors identified a non-cited violation of 10 CFR Part 50, Appendix B, Criterion V, Instructions, Procedures and Drawings for twice failing to perform an adequate operability evaluation on the Division II diesel generator after the number 8 cylinder exhaust pipe cracked and later when two of four exhaust flange bolts failed. The finding is more than minor because it affects the mitigating systems cornerstone objective to ensure the availability, reliability, and capability of systems responding to initiating events to prevent undesirable consequences. The team determined that a Phase 3 significance determination was required because the finding screened as potentially risk significant due to potential loss of safety function of a single train. Region IV senior risk analysts performed a Phase 3 significance determination and determined that the issue represents a finding of very low safety significance (Green). This violation has a crosscutting aspect in the area of problem identification and resolution associated with the corrective action program because the licensee did not thoroughly evaluate problems such that the resolutions address causes and extent of conditions, as necessary. Specifically the licensee failed to properly prioritize and evaluate for operability a degraded Division II diesel generator Number 8 cylinder exhaust pipe and flange (P.1(c)
05000416/FIN-2009004-02	2009Q3	Grand Gulf	Failure to Maintain Operator Response Times to Fires	The inspectors identified a Green non-cited violation of Technical Specification 5.4.1(a), for failure to ensure that operators can respond in timely manner to safe shutdown panels in the auxiliary building with a fire in the main control room. The inspectors reviewed a condition report associated with response times of operators to a fire in the protected area with Mississippi river at flood stage. The inspectors questioned the adequacy of response times for fire brigade members and the safe shutdown operator in the event of fire in the control room with the designated operators being outside the protected area. The licensee determined a time critical task would not have been completed due to the safe shutdown operator being outside the protected area. The licensee entered this condition in the corrective action program as condition report CRGGN-2009-01416.The inspectors determined this finding to be more than minor since it affected the external events attribute of the Mitigating Systems Cornerstone objective to ensure the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences. Using the Manual Chapter 0609, Significance Determination Process, Phase 1 worksheet, it was determined that the finding screened as potentially risk significant due to external events and required the regional senior reactor analyst to perform a Phase 3evaluation. The senior reactor analyst determined the likelihood that control room abandonment occurs while the safe shutdown operator is out of the protected area is 9.78E-8. The change in core damage frequency is lower than this value and small enough that large early release frequency is not required to be considered. Therefore the issue is (Green) of very low safety significance. The cause of this finding has a crosscutting aspect in the area of problem identification and resolution associated with corrective action program in that the licensee failed to perform an appropriate extent of condition when implementing corrective action associated with fire brigade response issue in 2008 P.1(c)
05000416/FIN-2009004-01	2009Q3	Grand Gulf	Failure to Monitor Performance of a Maintenance Rule Scoped System	The inspectors identified a Green noncited violation of10 CFR Part 50.65(a)(2) involving the failure to adequately monitor the performance of a maintenance rule scoped system. The licensees maintenance rule program required evaluation of the area radiation monitoring system for classification as a maintenance rule (a)(1) system after three failures within eighteen months. The licensee had identified two functional failures of the residual heat removal heat exchanger A hatch radiation monitor in June and July2008. The inspectors identified three other instances of functional failures on components that were used in plant emergency operating procedures and emergency preparedness procedures. These failures were not included in the licensees maintenance rule database. A total of five functional failures occurred in system components before the licensee considered evaluation of area radiation monitoring as a maintenance rule (a)(1) system in September 2009. The licensee entered this condition in the corrective action program as condition reports CR-GGN-2009-04853 and CR-GGN-2009-04857.The finding was more than minor because it was similar to Inspection Manual Chapter 0612, Appendix E, Example 7.d, in that equipment performance problems were such that effective control of performance or condition through appropriate preventive Maintenance Under (a)(2) could not be demonstrated. In addition, it affected 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. This finding was characterized under the significance determination process as having very low safety significance because the maintenance rule aspect of the finding did not cause an actual loss of safety function of the system nor did it cause a component to be inoperable. There is no crosscutting aspect associated with this performance deficiency since the cause of this issue does not reflect current licensee performance.
05000458/FIN-2009008-02	2009Q3	River Bend	Licensee-Identified Violation	The licensee identified a non-cited annotated with a violation of 10 CFR 50, Appendix B, Criteria III, Design Control, associated with a field change performed on the Division I diesel generator turbo-charger drain line modification. The licensee had identified a crack on the turbo-charger oil drain line connection to the Division I diesel generator. The licensee developed a modification to preclude recurrence of the leak. While installing the modification, the licensee performed an undocumented field change to route the drain line around a physical interference. The undocumented change placed the diesel generator in a degraded condition which if left uncorrected could have become a more significant safety concern. The licensee subsequently discovered the undocumented field change and took corrective action to restore the drain line to design specifications. The licensee documented the condition in the condition reporting process as Condition Report CR-RBS-2009-002296
05000528/FIN-2009006-08	2009Q1	Palo Verde	Failure to Promptly Identify and Correct a Condition Adverse to Quality with the Emergency Core Cooling System Piping	A self-revealing noncited violation of 10 CFR Part 50, Appendix B, Criterion XVI, Corrective Action, was identified for the failure of the licensee to promptly identify and correct a condition adverse to quality associated with the high pressure safety injection system piping. Specifically, between January 18, 1989, and October 12, 2006, the licensee failed to ensure that select sections of Unit 1 high pressure safety injection Train B piping were inspected to prevent erosion due to cavitation. This resulted in a through-wall leak in the high pressure safety injection Train B recirculation line. This issue was entered into the licensees corrective action program as Condition Report/Disposition Request 2932507.The performance deficiency associated with this finding involved the licensees failure to promptly identify and correct a condition adverse to quality associated with the high pressure safety injection system piping. The finding is greater than minor because it is associated with the equipment performance attribute of the mitigating systems cornerstone and affects the associated cornerstone objective to ensure the reliability and availability of systems that respond to initiating events. Using Manual Chapter 0609.04, Phase 1 Initial Screening and Characterization of Findings, the finding was determined to have a very low safety significance because the finding did not result in a loss of system safety function, an actual loss of safety function of a single train for greater than its Technical Specification allowed outage time, or screen as potentially risk-significant due to a seismic, flooding, or severe weather initiating event. This finding was evaluated as not having a crosscutting aspect because the performance deficiency is not indicative of current performanc
05000528/FIN-2009006-02	2009Q1	Palo Verde	Failure to Follow Procedure for Screening Significant Condition Adverse to Quality	The inspectors identified a Green noncited violation of 10 CFR Part 50, Appendix B, Criterion V, Instructions, Procedures and Drawings, for the licensees failure to follow procedures for identifying the significance of a significant condition adverse to quality. Specifically, the Action Request Review Committee screened Palo Verde Action Request 3221258 as an adverse Condition Report Disposition Request, despite the fact that the Procedure 01DP-OAP12 required it to be screened as significant. This error resulted in the failure to understand the failure mode associated with a safety related essential cooling water pump such that corrective actions would prevent recurrence. The licensee documented the failure to properly screen this issue for significance in Palo Verde Action Request 3288713.The finding is more than minor because the finding is associated with the equipment performance attribute of the mitigating systems cornerstone, and affects the cornerstone objective to ensure the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences. The inspectors utilized Manual Chapter 0609.04, Phase 1 Initial Screening and Characterization of Findings, to determine that the finding was of very low safety significance because it did not represent a design or qualification deficiency, did not result in a loss of safety function, or screen as a risk-significant external event. The cause of this finding is related to the problem identification and resolution crosscutting component of corrective action program, in that licensee failed to properly classify and evaluate a significant condition adverse to quality (P.1c
05000528/FIN-2009006-07	2009Q1	Palo Verde	Inadequate Procedures for Performing Operability Determinations	The inspectors identified a noncited violation of 10 CFR Part 50, Appendix B, Criterion V, Instructions, Procedures, and Drawings, for the failure of operations personnel to follow the corrective action program to ensure that degraded and nonconforming conditions associated with safety related systems and systems important to safety were reviewed for operability. Specifically, between December 21, 2006 and January 30, 2009, operations personnel failed to perform adequate operability determinations of Palo Verde Action Requests associated with the component design basis review project and other site projects, resulting in 97 Palo Verde Action Requests that either needed an immediate operability determination or a functional assessment, or needed more information to provide reasonable assurance of operability. Of the 97 examples20 occurred following implementation of corrective actions to improve this process and therefore are reflective of current performance. This issue was entered into the licensee\'s corrective action program as Palo Verde Action Request 3281099.The finding is greater than minor because it is associated with the equipment performance attribute of the mitigating systems cornerstone and affects the cornerstone objective of ensuring the reliability of systems that respond to initiating events to prevent undesirable consequences. Using Manual Chapter 0609.04, Phase 1 Initial Screening and Characterization of Findings, the finding was determined to have a very low safety significance because the finding did not result in a loss of system safety function, an actual loss of safety function of a single train for greater than its Technical Specification allowed outage time, or screen as potentially risk significant due to a seismic, flooding, or severe weather initiating event. This finding has a crosscutting aspect in the area of human performance associated with resources because 11 of the 20examples, reflective of current performance, were the result of inadequate procedural guidance governing the conduct of operability determinations to ensure that conditions adverse to quality are properly evaluated for their potential operability impacts (H.2c

Semantic search

Query log

Navigation menu