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05000390/FIN-2009006-012009Q2Watts BarFailure to Promptly Correct a Condition Adverse to Quality Associated with the \'A\' Shutdown Boardroom ChillerA self-revealing non-cited violation (NCV) of 10 CFR 50, Appendix B, Criterion XVI was identified for failure to take timely and effective corrective action to maintain the capillary line to the Essential Raw Cooling Water (ERCW) condenser water temperature control valve (1-TCV-67-158) filled with water to ensure operability of the A Shutdown Boardroom chiller. The licensee vented the line, returning the chiller to service, and entered the issue into their CAP. The finding is more than minor because it affects the Mitigating Systems Cornerstone objective of ensuring the availability of the A Shutdown boardroom chiller, which is a system that responds to initiating events. It is also associated with the cornerstone attribute of equipment availability and reliability. This finding was assessed using the Phase 1 screening worksheet of the SDP and determined to be of very low safety significance (Green) because it did not result in an actual loss of safety function of a single train for greater than the Technical Specification (TS) allowed outage time and was not potentially risk-significant due to external events. This finding has a cross-cutting aspect in the Work Control component of the Human Performance area (H.3(b)), because the licensee failed to properly prioritize the compensatory maintenance activities to support safety system operability of an operable but degraded system
05000390/FIN-2009006-022009Q2Watts BarFailure to Follow Plant Procedures for Canceling Preventive MaintenanceA self-revealing NCV of Technical Specification 5.7.1 was identified for the licensees failure to follow plant procedures which resulted in the failure of the Unit 1 Shield Building Vent Radiation Monitor System, an effluent radiation monitor. The inspectors determined the licensees failure to follow site procedures for PM cancellation was a performance deficiency and a finding. The inspectors reviewed Inspection Manual Chapter (IMC) 0612 and determined that the finding is more than minor because the finding is associated with the plant facilities/equipment and instrumentation attribute (reliability of process radiation monitors) of the radiation safety cornerstone (public radiation safety) and adversely affected the cornerstone objective of ensuring adequate protection of public health and safety from exposure to radioactive materials released into the public domain as a result of routine civilian use. The finding was assessed using the IMC 0609, Appendix D, Public Radiation SDP, and because there was no failure to implement the effluent program, the finding was determined to be of very low safety significance (Green). No cross-cutting aspect was assigned to this finding because the direct cause was not considered indicative of current performance
05000259/FIN-2009002-012009Q2Browns FerryInappropriate Change to SSI Entry Conditions For Appendix R Fire Events (Section 1R15)On December 23, 2008, the licensee issued Revision 2 of 0-SSI-001, which instituted a significant change to the SSI Entry Conditions. In essence this revision, added an entry condition based on the operators ability to restore and maintain reactor water level above +2 inches on the narrow range scale with available equipment. With this change in effect, operators would not enter the SSIs during an Appendix R fire event unless they were unable to restore and maintain reactor water level above +2 inches. As long as operators could maintain reactor water level during a fire event, they would continue to use the Emergency Operating Instructions (EOI) in lieu of the SSIs. In January 2009, the inspectors reviewed the affect of 0-SSI-001, Revision 2, upon the operators ability to align and operate designated safe shutdown equipment in a manner that would ensure their capability to perform their intended functions during a 10CFR50, Appendix R, fire event. Based on this review, the inspectors questioned the adequacy of the revised SSI entry conditions to ensure critical parameters (e.g., Suppression Pool temperature) would be maintained consistent with assumptions in the safe shutdown analyses (SSA). Failure of the operators to enter the SSIs at the right time could invalidate the critical SSI timelines for operator actions to ensure reactor core and containment cooling functions are met. To address the inspectors concerns regarding the potential adverse impact on critical assumptions in the SSAs as a consequence of delayed entry into the SSIs by the operators, the licensee initiated PER 162431. After further review of the inspectors concerns, the licensee subsequently determined that the Entry Conditions of 0-SSI-1 did not ensure timely entry into the safe shutdown procedures in the event that decay heat removal capability was lost due to fire damage. The Revision 2 procedure change evaluation of 0-SSI-001 did not consider the potential impact on decay heat removal and containment cooling functions during a fire event. The licensee initiated PER 162779 to promptly address this specific issue. On February 9, 2009, the licensee issued Revision 3 of 0-SSI-001 which changed the Entry Conditions to include additional provisions for ensuring timely entry into the SSIs that would assure critical SSA assumptions were met to allow decay heat removal and containment cooling functions to be fulfilled. This SSI revision, and a revision to the licensees Fire Protection Report, were the primary corrective actions to resolve PER 162779. In order to address the inspectors original, overall concern, as part of the corrective actions for PER 162431, the licensee committed to conduct a comprehensive re-evaluation of the SSI entry conditions to assure they were consistent with all SSA assumptions and SSI timelines for any Appendix R fire event. (Note: following further dialogue with the NRC staff regarding acceptability of SSI entry conditions, the licensee also initiated PER 164685 and subsequently issued Revision 4 of 0-SSI-001, on February 27, 2009, which changed the Entry Conditions back to the way they were in Revision 1. The Entry Conditions prescribed by Revision 1 and 4 of 0-SSI-001 were essentially based only on the magnitude of the fire, and did not include qualifiers related to plant parameters (e.g., reactor water level, suppression pool temperature).) In order to fully assess the safety and enforcement implications regarding the adequacy of the revised SSI entry conditions, additional information from the licensee will be needed. Consequently, pending completion of the licensees comprehensive reevaluation, and further review by the NRC, this issue will be identified as URI 05000259, 260, 296/2009002-01, Inappropriate Change to SSI Entry Conditions For Appendix R Fire Events
05000259/FIN-2009002-032009Q1Browns FerryUnit 1 RPV Flange Leak Due to Lack of Prompt Identification and Resolution (Section 4OA2.3)A Green self-revealing non-cited violation of 10 CFR 50, Appendix B, Criterion XVI was identified for not promptly identifying and correcting a condition adverse to quality associated with steam cuts and/or defects in the Unit 1 reactor pressure vessel (RPV) flange that resulted in increased unidentified reactor coolant system (RCS) leakage during Cycle 7 operation. The Unit 1 RPV head and flange surfaces were repaired during the following refueling outage. This finding was entered into the licensee\'s corrective action program (CAP) as Problem Evaluation Report 155705. This finding was greater than minor because it was associated with the Initiating Event Cornerstone attribute of Equipment Performance, and adversely affected the cornerstone objective to limit the likelihood of those events that upset plant stability during at-power operations. The finding was determined to be of very low safety significance (Green) because the maximum unidentified RCS leakage from the Unit 1 RPV flange leak was much less than the Technical Specification limit for unidentified RCS leakage of 5 gpm and would not have affected other mitigation systems resulting in a total loss of their safety function. No cross-cutting aspect was assigned to this issue because the direct cause was not considered as indicative of current performance due to improvements in the CAP since this issue occurred. (Section 4OA2.3
05000259/FIN-2009002-042009Q1Browns FerryMain Generator Voltage Regulator Relay Failure Results in Unit 2 Reactor Scram (Section 4OA3)A Green self-revealing finding was identified for inadequate design control and replacement of the 43A relay in the Unit 2 main generator voltage regulator control circuit that resulted in a reactor scram due to a main turbine generator trip from a loss of main generator excitation. The failed 43A relay was subsequently replaced with another model relay better suited to low energy control circuit applications. This finding was entered into the licensee\'s corrective action program as Problem Evaluation Report 153987. This finding was greater than minor because it was associated with the Initiating Event Cornerstone attribute of Design Control, and adversely affected the cornerstone objective to limit the likelihood of those events that upset plant stability and challenge critical safety functions during at-power operations. The finding was determined to be of very low safety significance (Green) because it did not contribute to both the likelihood of a reactor trip and the likelihood that mitigating equipment or functions were not available.
05000259/FIN-2009002-022009Q1Browns FerryInadequate Surveillance Procedure Causes Loss of Unit 1 RHR System Safety Function (Section 1R22)A self-revealing non-cited violation of Technical Specification 5.4.1, Procedures, was identified for an incorrect Unit 1 surveillance procedure that instructed technicians to install a jumper in the wrong location which resulted in the inadvertent lockout of the Loop II residual heat removal (RHR) pumps automatic start feature while the Loop I RHR pumps were removed from service for testing. The improperly installed jumper resulted in the RHR system being unable to perform its safety function. The immediate corrective actions for this event included removal of the jumper to restore the automatic start feature of the RHR Loop II pumps, revision to the surveillance procedure to reflect the correct location for the jumper, and completion of the surveillance. This finding was entered into the licensees corrective action program as Problem Evaluation Report 166487. The finding was determined to be more than minor because it was associated with the Mitigating Systems Cornerstone attribute of Procedure Quality and adversely affected the associated cornerstone objective to ensure the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences. A Phase 2 analysis was performed because the event represented a loss of the RHR system safety function. The Phase 2 analysis using Appendix A, Technical Basis for At- Power Significance Determination Process, of IMC 0609 determined that the finding was of very low safety significance (Green). The cause of this finding was directly related to the cross cutting area of Problem Identification and Resolution and the aspect of thorough evaluation of identified problems because a prior licensee-identified procedural discrepancy regarding the location of this jumper was not adequately evaluated and resolved to ensure the jumper would be installed in the correct circuit (P.1(c)). (Section 1R22)
05000327/FIN-2009002-022009Q1SequoyahProcedure 0-MA-REM-000-001.0, Extended Station Blackout, Did Not Close Hydrogen Igniter BreakersAn NRC inspector identified a Green finding for the licensees failure to implement a docketed commitment made to the NRC. Specifically, the licensee did not adequately revise procedures in accordance with a self-imposed standard to provide backup power to at least one train of hydrogen igniters in response to Generic Safety Issue 189 Susceptibility of Ice Condenser and Mark III Containments to Early Failure from Hydrogen Combustion During a Severe Accident. The revised procedures failed to close the supply breaker to the hydrogen igniter. The licensee entered this issue into their corrective action program as Problem Evaluation Report 144301. The finding is more than minor because it is associated with the Procedure Quality attribute of the Reactor Safety/Barrier Integrity Cornerstone. The inadequate procedure affects the cornerstone objective to provide reasonable assurance that physical design barriers, specifically maintaining the functionality of containment, protect the public from radio nuclide releases caused by accidents or events. For this finding, the accident sequences are associated with station blackouts. A Phase 3 Significance Determination Process evaluation was required to ascertain the safety significance. A regional senior reactor analyst performed a Phase 3 evaluation and determined that this performance deficiency was of very low safety significance (Green) (Section 4OA5.5)
05000327/FIN-2009002-012009Q1SequoyahPressurizer Pressure Transient due to Inadequate Maintenance ProcedureA Green self-revealing non-cited violation of Unit 2 Technical Specification 6.8.1 was identified for the licensees failure to have an adequate procedure to ensure replacement of the pressurizer pressure master controller would not adversely impact plant stability. Specifically, on January 7, 2009, operators placed a pressurizer spray valve controller in automatic while the master controller was in manual with a large demand output signal present. This resulted in the spray valve fully opening and an associated reactor coolant system pressure transient. Operators immediately restored pressure to its normal value, and the finding was entered into the licensees corrective action program as Problem Evaluation Report (PER) 160504. The finding was greater than minor because it was associated with the procedure quality attribute of the initiating events cornerstone and affected the cornerstone objective to limit the likelihood of those events that upset plant stability and challenge critical safety functions. Using Manual Chapter 0609, Significance Determination Process, Attachment 4, the finding was determined to have very low safety significance (Green) because it did not contribute to both the likelihood of a reactor trip and the likelihood that mitigating systems will not be available. The cause of this finding was determined to be in the cross-cutting area of human performance associated with work practices and the aspect of human error prevention, in that, during the pre-job brief, the operators discussed minimizing the master controller demand signal but failed to self and peer check to ensure that the procedural steps were consistent with the appropriate actions (H.4(a)) (Section 1R19)
05000259/FIN-2009002-062009Q1Browns FerryLicensee-Identified ViolationThe licensee identified a violation of Unit 1 TS 3.4.3 which required that twelve of thirteen MSRVs lift at a setpoint within plus or minus three percent of a specified value. Contrary to this, during surveillance testing following the Unit 1 Cycle 7 refueling outage, the licensee discovered that ten MSRVs did not meet the TS allowed pressure band as described in the licensees PER 159200. This finding was determined to be of very low safety significance because the as-found lift setpoint conditions of the Unit 1 MSRVs were analyzed and determined to meet the design basis criteria for an over-pressurization event
05000259/FIN-2009002-052009Q1Browns FerryLicensee-Identified ViolationThe licensee identified a violation of Unit 1 TS 3.4.4.a which required that no RCPB leakage could exist during unit operation. Contrary to this, during an operating pressure test at the end of the Unit 1 Cycle 7 refueling outage, the licensee identified a through wall leak in the RPV Nozzle N11B safe end that would have existed during unit operation. This finding was determined to be of very low safety significance because any potential increase in the LOCA initiating event frequency would have been extremely small considering the size of the crack, the propagation mechanism, and the fact it was identified at the end of the operating cycle with no prior evidence of leakage. Furthermore, even total failure of the RPV instrument line nozzle would have been well within the capacity of existing LOCA mitigating systems
05000352/FIN-2008005-022008Q4LimerickInadequate Post-Maintenance Test following Containment Isolation System Relay ReplacementThe inspectors identified a NCV of Technical Specification 6.8.1, Administrative Controls-Procedures, because Exelon did not maintain adequate maintenance procedures associated with work performed on the Unit 2 Nuclear Steam Supply Shutoff System (NSSSS). Specifically, the procedures, which performed system relay replacements, did not contain adequate post-maintenance testing (PMT) to demonstrate that the Technical Specification required response times of all circuits affected by the maintenance were satisfied. The inspectors determined that this finding was more than minor because it was associated with the procedure quality attribute of the Mitigating System cornerstone, and affected the Mitigating System cornerstone objective to ensure the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences. As a result of the inadequate PMT, additional unavailability was accrued, and an engineering evaluation was required to demonstrate satisfactory response times. The finding was determined to be of very low safety significance(Green) because it did not represent a loss of safety function. The inspectors determined this finding had a cross-cutting aspect in Human Performance, Resources, because Exelon did not provide complete and accurate work packages to assure nuclear safety. Specifically, the NSSSS was returned to service without all the required post-maintenance testing being performed to demonstrate operability. (IMC 0305 aspect:H.2(c)) (Section 1R19
05000259/FIN-2008005-022008Q4Browns FerryLicensee-Identified ViolationIn March 2002, Unit 2 Reactor Zone Supply Secondary Containment Isolation Damper 2-DMP-64-14 failed in the open position due to the use of an improper lubricant in its solenoid valve. During an extent of condition review of this condition adverse to quality (i.e., defective material), the licensee determined that many of the solenoid valves used to control the secondary containment isolation dampers for Units 1, 2, and 3 were the same model, and susceptible to the same failure mode, as the solenoid valve for 2-DMP-64-14. According to 10 CFR 50, Appendix B, Criterion XVI, Corrective Action, requires that conditions adverse to quality, such as defective material and equipment, are to be promptly identified and corrected. However, contrary to Criterion XVI, the licensee failed to correct this adverse condition to quality on Unit 1 when they inadvertently omitted replacing the Unit 1 solenoid valves when the Unit 2 and 3 solenoid valves were replaced. The licensee identified this omission during surveillance testing in September 2008, when both of the Unit 1 Reactor Zone Exhaust Secondary Containment Isolation Dampers failed open (1- DMP-64-42 and 43) due to the improper lubricant in their solenoid valves. This finding was considered to be of very low safety significance because it only represented a degradation of the radiological barrier function of the reactor building secondary containment. The licensee entered this finding into the CAP as PER 152333
05000259/FIN-2008005-012008Q4Browns FerryFailure to Maintain Requalification Examination IntegrityThe inspectors identified a non-cited violation of 10 CFR 55.49 for engaging in an activity that compromised, or would have compromised but for detection by the inspectors, the integrity of examinations required by 10 CFR 55.59 that were administered in 2007 and that were planned to be administered in 2008. The examination compromise would have affected the equitable and consistent administration of the operational portion of the requalification annual examination. The inspectors identified that three job performance measures (JPM) sets administered in 2007 contained an unacceptable number of JPMs that had previously been administered during that same examination cycle. The inspectors also identified that the JPMs scheduled to be performed in the last three weeks of the 2008 requalification examination had all been previously administered in the first three weeks of the 2008 requalification examination. When notified of the examination schedule overlap issue, the licensee changed the examination schedule to prevent the overlap issue in 2008 and entered the problem into their corrective action program as problem evaluation report 158635. This finding is more than minor because if left uncorrected, it could become a more significant safety concern, in that, licensed operators would not be adequately tested to ensure an acceptable knowledge level for performing licensed duties. Using the Licensed Operator Requalification Significance Determination Process, this finding was determined to be of very low safety significance (Green) because the performance deficiency was immediately corrected upon discovery. The cause of the finding was that the licensee did not comply with requirements of TRN-11.10, Annual Requalification Examination Development and Implementation. The finding was related to the crosscutting aspect of procedural compliance of the work control component of the crosscutting area of Human Performance (H.4(b)). (Section 1R11.2
05000352/FIN-2008005-012008Q4LimerickChanges to Technical Specification 3.8.1 BasesOn September 30, 2008, operators racked out one of the two offsite power supply feeder breakers to 4kV Emergency Bus D11 (201-D11) for maintenance. The inspectors noted that although one of the two offsite power sources was not available to4kV Emergency Bus D11, operators did not declare the associated offsite power circuit(201 Circuit) inoperable and enter into TS Limiting Condition for Operation (LCO)3.8.1.1, AC Sources V Operating, Action f, which requires, in part, performing Surveillance Requirement (SR) 4.8.1.1.a within one hour and also entails entering a 72hour LCO shutdown action statement. The inspector noted that TS SR 4.8.1.1.1.b could not be met if one of the two offsite power source breakers was racked out. That SR states Each of the above required independent circuits between the offsite transmission network and the onsite Class 1E distribution system shall be demonstrated OPERABLE in accordance with the Surveillance Frequency Control Program by transferring, manually and automatically, unit power supply from the normal circuit to the alternate circuit. With an offsite power supply feeder breaker racked out and unavailable to a nonsite 4kV emergency bus, manual and automatic transfer was not possible. In addition, TS 4.0.1 states, in part, that, Failure to meet a Surveillance, whether such failure is experienced during the performance of a Surveillance or between performances of the Surveillance, shall be failure to meet the Limiting Condition for Operation. The inspectors referenced TS Bases 3/4.8.1, which described that an offsite circuit is considered to be inoperable if it is not capable of supplying at least three, Unit 1 4kVemergency buses. Recognizing that the TS Bases 3/4.8.1 appeared to conflict with the SR, the inspectors questioned the history of the bases. Exelon informed the inspectors that the bases were modified in 2000 to define an operable offsite source as one capable of supplying power to three of the four emergency buses in the unit, through Engineering Change Request (ECR) LGS ECR 99-00682.The inspectors reviewed LGS ECR 99-00682 and found that Exelons 10 CFR 50.59screening for the TS bases change concluded that the change was an enhancement, and, as such, a change to the TS was not required. The ECR described the change as taking advantage of system redundancy similar to the design of the EDGs. Specifically, section 8.3.1.1.2.2 of the UFSAR provides results of a single failure analysis (focused on the EDGs but also applicable to the 4kV emergency buses) that concludes that any combination of three-out-of-four buses could withstand a single failure and still safely shut down the plant. The inspectors reviewed the Limerick licensing basis and found several conflicts with Exelons conclusion. Namely, the TS bases change:FnConflicted with the facility as described in the UFSAR Sections 8.2.1, Offsite Power Sources. Section 8.2.1.1 describes that Both offsite sources are available continuously to the Class 1E buses; andFnConflicted with the description of the onsite emergency power system description as documented in NUREG-0991, Safety Evaluation Report Related to the Operation of Limerick Generating Station, Units 1 and 2, dated August 1983. Section 8.3.1 of the Safety Evaluation Report stated that Each 4.16-kV ESF (Engineered Safety Feature) bus is normally connected to two offsite power sources, designated as preferred and alternate power supplyK; and,FnAlthough the ECR described the change as taking advantage of system redundancy similar to the design of the EDGs, the inspector noted that a TS Action is required to be entered for one EDG being inoperable. The inspectors determined that the modification of the TS bases appeared to be in conflict with the requirements of TS LCO 3.8.1.1 through the application of SR4.8.1.1.1.b. Therefore, it appeared that the change should have required a change to the TS, which would have required NRC review. Making the TS bases change without changing the TS appeared to be contrary to 10 CFR 50.59 (c)(1)(i) which states that a licensee may make changes in the facility as described in the final safety analysis reportKwithout obtaining a license amendment pursuant to (paragraph) 50.90 only if a change to the technical specifications incorporated in the license is not required. In addition, the changes made to the TS bases appeared to be contrary to TS 6.8.4.h,Technical Specification Bases Control Program, which contains similar requirements. Exelon acknowledged the inspectors observations and agreed to provide additional information to show that the changes made to the TS bases did not require prior NRC approval. Pending the review of the additional information to be provided by Exelon, this issue is unresolved
05000327/FIN-2008003-022008Q2SequoyahProcedure 0-MA-REM-001.0, Extended Station Blackout, Does Not Close Hydrogen Igniter BreakersThe licensee modified their Extended Station Blackout procedure to support the additional function and clarified its intent regarding power to the hydrogen igniters. While preparing to discuss restoration of power to the igniters with the inspector, the licensee identified a deficiency with the Extended Station Blackout procedure. Appendix R of this procedure provided guidance on restoring power to the 480V C and A Vent Boards, which energize the igniters; however, it left all the individual load breakers (including the breakers for the hydrogen igniters) in the OPEN position. Guidance for reclosing the hydrogen igniter breaker was omitted when the igniters were addressed in Revision 3 of the procedure. The licensee revised the procedure and generated a problem report to address this issue (PER 144301). This issue is being considered an Unresolved Item pending further inspection and review: URI 05000327, 328/2008003-02, Procedure 0-MA-REM-000-001.0, Extended Station Blackout, Did Not Close Hydrogen Igniter Breakers
05000327/FIN-2006005-022006Q4SequoyahInability to Perform Required Actions of AOP-N.08, Appendix R Fire Safe Shutdown (Section 1R15)On October 28, 2005, a procedure change to AOP-N.08, Appendix R Fire Safe Shutdown, was implemented. This change incorporated updated guidance provided by a Westinghouse technical bulletin (TB -04-022) concerning RCP seal performance during Appendix R fires and a loss of all pump seal cooling. This change reduced the time available to perform manual actions and restore RCP seal flow from 24 minutes to 13 minutes. In the event of an Appendix R fire resulting in a spurious safety injection signal, plant procedures required that all RCS injection sources be stopped to prevent filling the pressurizer solid. The vendor guidance stated that actions taken to prevent this condition and restore RCP seal flow should be completed within 13 minutes to prevent seal damage. The actions outlined by AOP-N.08 required an auxiliary unit operator (AUO) to manipulate several valves in the appropriate Charging Pump room and then a CCP restarted to restore seal flow. Specifically, the AUO was to open a dedicated flow path to the RCP seals using manual valve 62-526 (A-train), or 62-534 (Btrain) and close the associated CCP manual discharge valve, 62-527 (A-train) or 62-533 (B-train) to the CCP Injection Tank (CCPIT). To support the procedure change, these manipulations were subjected to a manual action validation that consisted of a table top review of the necessary steps. The licensee determined that the CCP manual discharge valves to the CCPIT could be closed by an individual AUO in 5 minutes and 20 seconds. Prior to the procedure being approved, PER 91383 was written on October 24, 2005. The PER addressed concerns by at least one plant AUO that the manual actions required by the change to procedure AOP-N.08 may not be able to be completed within the time required. PER 91383 requested the need to further evaluate the time necessary to perform the manual actions by actual valve manipulations, or whether additional procedure changes were needed to provide more margin to the required time. The corrective action planned was to perform a timed valve stroke of CCP discharge valve 2-62-527 to validate procedural change assumptions. Work Order (WO) 06- 771729-000 was written to implement and track this action during an appropriate CCP maintenance period. PER 91383 was closed as completed on February 24, 2006 based on the WO being written. On November 9, 2006, during a self-assessment, the licensee determined that the WO had not been completed and was not scheduled for performance until January 22, 2007. PER 114455 was written to document the incomplete corrective action. Upon review of PER 114455, the inspectors questioned the licensee on the valves history, the status of corrective actions, and whether a valid safety concern existed if the valve could not be operated within the prescribed time. Prior to resolution by the licensee, on November 27, 2006, during Unit 2 refueling outage activities, operators closed valve 2-62-527 to support maintenance. The operators reported that the valve was very difficult to operate and required approximately 30 minutes for two AUOs to shut the valve. This observation was documented in in PER 115490 and supported the initial concern expressed in PER 91383. This information prompted the license to evaluate the consequences of the additional time needed to operate valve 2-62-527 with plant Appendix R
05000327/FIN-2005011-052005Q4SequoyahReliance on Local Manual Operator Actions for Appendix R FiresThe team identified an URI related to licensee reliance on many local manual operator actions for mitigation of Appendix R, Section III.G.2 fires, where operators would be shuting down the plant from the main control room. This issue is unresolved pending further NRC review of the licensing basis. The team noted that the licensees procedure AOP-N.08, Appendix R Fire SSD, relied on many local manual operator actions to mitigate a fire in FAA-070 or FAA- 095 in lieu of protecting or separating cables per Appendix R, Section III.G.2. The licensee had no approved NRC deviations from the requirements of Appendix R, Section III.G.2 for these manual actions. However, licensee personnel believed that some of the actions had been specifically reviewed and accepted by the NRC, as documented in Inspection Report 05000327,328/88-24, which was referenced by NRC SER (NUREG-1232). The licensee also stated that the NRC had approved a general reliance on local manual operator actions instead of protecting or separating cables per Appendix R, Section III.G.2. The licensee had reviewed and walked down each action, and considered each action to be feasible. With the exception of the action to locally control motor driven AFW pump flow (described above), the team found these actions to be feasible. This issued is unresolved pending further NRC review of the licensing basis. This issue is identified as URI 05000327,328/2005011-05, Reliance on Local Manual Operator Actions for Appendix R Fires.
05000327/FIN-2005011-042005Q4SequoyahAppendix R Operator Action to Throttle AFW in Main Steam Valve Vault RoomThe team identified an URI related to a potentially non-feasible local manual operator action that was relied upon for SSD during a large fire in each of the three fire areas that were the focus of this inspection. The local manual action was to throttle AFW in the main steam valve vault room with or without lights. This issue is unresolved pending further NRC review of the licensing basis. During plant walkdowns of local manual operator actions that would be needed to mitigate a severe fire in FAC-17, FAA-070, or FAA-095, the team identified a potentially non-feasible local manual operator action. The local manual action was for an auxiliary unit operator (AUO) to throttle AFW flow to two steam generators in the Unit 1 main steam valve vault room and another AUO to perform a similar action in the Unit 2 main steam valve vault room. The action was required by AOP-N.08, Appendix G and AOP-C.04, Appendix J. During the walkdowns, the team observed that the Unit 2 main steam valve vault room was completely dark. All of the normal lights were extinguised and the installed Appendix R emergency lights were off. Licensee investigation determined there was no lighting because all of the normal light bulbs were burned out. The emergency lights were designed to come on only when electrical power to the normal lights was lost. Because electrical power had not been lost, no lighting was illuminated in the room. The lack of normal lighting had not been recognized because plant safety rules did not allow operators to go into the main steam valve vault rooms alone due to heat stress concerns, and there was no plant requirements to routinely enter the rooms during plant operation to check on the conditions in the rooms. As a result of the licensee not maintaining the normal lighting, had a severe (Appendix R) fire occurred in FAA-070, FAA-095, FAC-017, or any of many other fire areas, an AUO may have had to locally control AFW flow in the Unit 2 main steam valve vault room in the dark. The team walked down the operator action in the dark Unit 2 main steam valve vault room with an operator (using flashlights), and judged that the action was not feasible. The action was found to be too difficult and had a high likelihood of failure. Difficulty factors included: complete darkness except for a flashlight, heat stress, climbing ladders in the dark while holding a flashlight and avoiding hot pipes and head-knocking steel supports, loud noise from steam generator relief valves that would be lifting nearby, no local indications for throttling the valves, poor communications (the AUO would need to climb down a ladder and exit the valve room repeatedly to talk on the radio to the main or auxiliary control room), throttling with a gate valve (which would provide very uneven flow control), the action was time critical (to be performed within 30 minutes), and one AUO would have to perform the action alone. Licensee personnel stated that one AUO could be assigned to perform this action because plant safety rules related to heat stress did not apply during emergencies such as Appendix R fires. The team noted that if both units were affected by an Appendix R fire, then all available on-shift AUOs would be needed to perform SSD actions. There would be no extra AUOs available to send more than one to a main steam valve vault room. After the walkdowns, licensee personnel documented that they considered the action to be feasible for one AUO to perform even without lighting. The licensee promptly replaced the normal light bulbs in the Unit 2 main steam valve vault room and the team verified that the lights were on. The team noted that the licensee had installed backup air supply bottles (located outside the main steam valve vault rooms) that could enable the control room to operate the AFW air-operated flow control valves if the normal instrument air was lost; however, that backup air supply was not used in the Appendix R SSD procedures. In lieu of protecting cables to the AFW flow control valves from fire damage, the licensee was relying on the local manual actions in the main steam valve vault rooms. The team reviewed standards related to maintaining normal lighting for Appendix R SSD actions. Where the approved fire protection program allows certain local manual operator actions, those actions are expected to be capable of being reliably performed under the anticipated circumstances. Where licensees are relying on unapproved local manual actions, the actions can be considered adequate temporary compensatory measures if they are feasible. Feasibility and capability of being reliably performed involve adequate lighting. 10 CFR 50, Appendix R requires that operators be able to safely shut down the plant with or without offsite power (i.e., with or without normal lighting). Appendix R, Section III.J, Emergency Lighting, requires that emergency lighting be provided in all areas needed for operation of SSD equipment and for access and egress thereto. The statements of consideration (SOC) for Appendix R, Section III.J indicate that the basis for the emergency lighting assumed that normal lighting would also be available. The SOC stated: ...operators involved in safe plant shutdown should not also have to be concerned with lighting in the area, and it is prudent to provide 8-hour emergency lighting capability to allow sufficient time for normal lighting to be restored with a margin for unanticipated events. The acceptability of the local manual operator action to throttle AFW flow in the main steam valve vault room, with or without lighting, is unresolved pending further NRC review of the licensing basis for the action. This issue is identified as URI 05000327,328/2005011-04, Appendix R Operator Action to Throttle AFW in Main Steam Valve Vault Room.
05000327/FIN-2005011-022005Q4SequoyahUnprotected Power Cables to Vital Inverters in Unit 1 480V Board Room 1BThe team identified an URI associated with unprotected alternating current (AC) power cables to Unit 1 vital inverter 1-II and Unit 2 vital inverter 2-II. The cables were routed through the north end of the Unit 1 480V Board Room 1B (Fire Area FAA- 095) without protection or separation from fire damage (as required by Appendix R, Section III.G.2). The licensees SSA for SSD of Unit 1 and Unit 2 relied on the cables not being damaged by a severe fire in that area. To compensate for the unprotected cables, licensee personnel added a local manual operator action to the fire response procedures. This issue is unresolved pending further NRC review of the licensing basis. The licensees SSA for FAA-095 divided the fire area into three fire zones identified by column lines A3-A4, A4-A6, and A6-A8. Based on these fire zone descriptions the licensee analyzed what electrical equipment would be impacted by a fire in the affected zone. The licensees electric circuit analysis for a fire occurring between column lines A3 and A4 in FAA-095 (the north end of the room) concluded that vital inverters 1-II and 2-II, which were located in the south end of the room, would be available to support SSD. The analysis concluded that only vital inverters 1-I and 2-I, which were located in the north end of the room, would be lost for a fire in this zone. However, the 480V AC power cables to vital inverters 1-II and 2-II were routed through the north end of the Unit 1 480V Board Room 1B without protection or separation from fire damage (as required by Appendix R, Section III.G.2). The cables were approximately 11 feet from the 120V AC vital inverter 1-I and there were intervening 480V MCCs and cable trays in that 11 feet. Consequently, a fire in the north end of fire area FAA-095, between column lines A3 and A4, could result in loss of the 480V AC normal power supply cables to the 120V AC vital inverters 1-II and 2-II. Loss of the 480V AC power supply cable from fire damage would cause the vital inverters 1-II and 2-II to use their direct current (DC) power supply. Because the load of the inverters on the DC power supply would exceed the capacity of the battery charger, it could result in the complete discharge of the 125V DC battery and cause the inverters and other loads on the DC bus to be lost. The licensees analysis of record indicated that the battery charger and battery could maintain power to the 125V DC Vital Battery Board II and 120V AC Vital Instrument Power Board 1-II and 2-II loads for least four hours without the 480V AC power to the inverters. The licensee entered this issue into their corrective action program in Problem Evaluation Report (PER) 91841. In addition, the licensee took prompt corrective action to revise the fire procedure to add local manual operator actions to energize the spare Inverter 0-II, transfer the 120V AC Vital Instrument Power Board 1-II to its alternate supply, and de-energize inverter 1-II, all within four hours. The licensee stated that walkdown data showed that the actual loading on the battery/charger combination would be low enough such that the loads could be maintained for more than 8 hours. The team reviewed Design Change Notice (DCN) D-20071, Rev. a, which installed new vital inverters 1-II and 2-II and associated AC power cables (1PL4915B and 2PL4910A) in 2001. The DCN involved the installation of eight new inverters on the Unit 1 and Unit 2 vital power systems. The DCN was approved for implementation on September 2, 1999, and the plant modifications were completed in 2001. The new inverters were physically located in the same rooms as the old inverters. The Nuclear Safety Assessment for Fire Protection in the DCN stated that the new and existing cables routed (or rerouted) for this modification have been evaluated and found to be acceptable in accordance with the SQN Fire Hazards Analysis, see Mini-Calculation SQN-26-D054EPMABBIMPFHA6. It also stated the following: A fire in some areas along the route requires manual actions as a result of new 480V feeders to the replacement 120V AC vital inverters. In each case, the spare inverter is to be energized, the 120V AC vital distribution panel is to be transferred to its alternate supply (spare inverter) and the Unit 1 inverter deenergized. The actions are to be completed within 4 hours. Based on the above, the team concluded that the original design change had concluded that failure of the cable between columns A3 and A4 in FAA-095 was likely due to fire damage and that local manual operator actions would be necessary to mitigate the cable failure. However, after the modifications were completed, the required operator actions had not been added to the post-fire SSD procedure. The team also had a concern that the design change was not consistent with the licensing basis for the plant (i.e.,10 CFR 50, Appendix R , Section III.G.2) in that local manual operator actions were being used in lieu of separation or protection of the cables. The use of manual actions in lieu of separation or protection may require NRC approval prior to implementation if it affects SSD. The design change analysis referenced NRC approved Deviation #11 to Section III.G.2.b of Appendix R to support acceptability of the DCN. Deviation #11 allowed intervening combustibles in the form of open ladder type cable trays, with sprinklers, to be installed between redundant cables which were separated by more than 20 feet. However, Deviation #11 did not allow redundant cables to be separated by only 11 feet, with intervening 480V MCCs and cable trays. This issue is considered an unresolved item pending further NRC review of the licensing basis and is identified as URI 05000327,328/2005011-02, Unprotected Power Cables to Vital Inverters in Unit 1 480V Board Room 1B.
05000327/FIN-2005011-012005Q4SequoyahReliance on 20-foot Separation Zones for Fire Protection in Unit 1 480V Board Room 1BThe team identified an unresolved item (URI) associated with reliance on 20-foot separation zones between redundant SSD equipment in Unit 1 480V Board Room 1B (Fire Area FAA-095). The 20-foot zones did not meet the requirements of 10 CFR 50, Appendix R, Section III.G.2 and also appear not to meet the basis for NRC approval of Deviation #11 related to those requirements. This issue is unresolved pending further NRC review of the licensing basis and the potential for the condition to adversely affect SSD. The licensees SSA for Fire Area FAA-095 relied on three separate 20-foot separation zones between redundant SSD equipment in the room. Fire Area FAA-095 contained three Unit 1 480V motor control centers (MCCs), all three Unit 1 battery chargers (train A, train B, & spare), two of four channels of vital inverters for Unit 1, and two of four channels of vital inverters for Unit 2. The SSA relied on at least two of the three Unit 1 battery chargers and one of the two channels of Unit 1 and Unit 2 inverters in the room not being damaged by a fire in the room. One 20-foot separation zone was located on the north side of the room, separating the train A battery charger (located in the north end of the room) from the spare battery charger (located in the middle of the room). Another 20 foot separation zone was located on the south side of the room separating the train B battery charger (located in the south end of the room) from the spare battery charger. The third 20-foot separation zone was located in the middle of the room, between the vital inverters 1-I and 2-I (located in the north end of the room) and vital inverters 1-II and 2-II (located in the south end of the room). 10 CFR 50, Appendix R, Section III.G.2 stated that redundant SSD cables and equipment could be separated by 20 feet, with no intervening combustibles or fire hazards, and with detection and automatic suppression installed in the area. Deviation #11 applied to the auxiliary building in general. It allowed 20-foot separation zones in this building with intervening combustibles in the form of cable trays provided that: 1) the cables had fuse and breaker coordination to minimize the potential for fires initiating from cable faults and 2) extra sprinklers were installed to compensate for cable trays partially blocking any sprinklers. The team noted that the licensee had not identified in FAA-095 or in engineering documents exactly where the 20-foot separation zones were located. The team estimated the areas of the three 20-foot separation zones in FAA-095 and observed that each one did not meet the requirements of 10 CFR 50, Appendix R, Section III.G.2 and also appeared not to meet the basis for Deviation #11. In addition to intervening cable trays, each of the 20-foot separation zones included intervening ignition sources in the form of 480V MCCs and inverters. Also, two inverters located in the south end of the room, in the 20-foot separation zone between the Train A battery charger and the spare battery charger, did not have sprinklers installed above them. Licensee personnel stated that the lack of sprinklers in the south end of the room had been approved by Deviation #4. Deviation #4 applied to the Appendix R, Section III.G.2 requirement that fire detection and automatic suppression be provided in areas containing redundant SSD equipment that is separated by less than a three-hour fire rated construction. Deviation #4 allowed the licensee to omit sprinklers at the south end of FAA-095 on the basis that inadvertent operation of a sprinkler system would cause unacceptable damage to the inverters and battery chargers. Also, fire loading in FAA- 095 was considered to be low. However, the team observed that the battery charger and inverters at the north end of FAA-095 had sprinklers installed above them and that fire loading in FAA-095 was not low. The team found that, after Deviation #4 had been approved by the NRC, licensee engineers had recalculated the fire loading in FAA-095 and found it to be high. Apparently the original calculation of fire loading had failed to include the cable insulation inside of the 480V MCCs, inverters, and battery chargers. Licensee engineers determined the increased fire loading did not adversely affect SSD and and thus was acceptable without further review by the NRC. The team concluded that the licensee had inappropriately applied two separate NRC approved Deviations to the south end of FAA-095. More importantly, the team was concerned that the three 480V MCCs that intervened in the three 20-foot separation zones represented significant fire hazards. They occupied most of the length of FAA-095, from the north end to the south end of the room. They included a total of 42 vertical sections, with each vertical section being a potential ignition source. Each vertical section had stacks of open cable trays directly above it, so that a fire that initiated in a vertical section could readily spread up to seven or more cable trays. NUREG-1805 fire models demonstrated that such a fire could cause a hot gas layer throughout the room which could damage the cables (all had non-qualified thermoplastic insulation) and the SSD equipment located in FAA-095, should the automatic sprinkler system fail. The team noted that the sprinkler system for FAA-095 had a higher likelihood of failure because it was a cross-zone preaction-type of system. The sprinkler piping in FAA-095 was normally dry. To put fire water into the piping, at least two smoke detectors from different zones in the room would have to activate and automatically open a valve. If the cross-zone detector circuit failed or the valve failed to automatically open, all of the sprinklers in FAA-095 would fail to deliver water. Sequoyah\'s license condition for fire protection allowed changes to the fire protection program provided that the changes did not adversely affect SSD. The licensee\'s evaluation determined that the existing 20-foot separation zones were acceptable. Licensee personnel concluded that the existing 20-foot separation zones did not adversely affect SSD and were acceptable with no further review by the NRC, because there were sprinklers above the cable trays and MCCs. This issue is considered an unresolved item pending further NRC review of the licensing basis and the potential for the condition to adversely affect SSD. This issue is identified as URI 05000327,328/2005011-01, Reliance on 20-foot separation zones for Fire Protection in Unit 1 480V Board Room 1B.
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