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	Quarter	Site	Title	Description
05000369/FIN-2007005-05	2007Q4	McGuire	Failure to Follow Procedure During Residual Heat Removal Pump 1B Performance Test	Failure to Follow Procedure During Residual Heat Removal (ND) Pump 1B Performance Test (PT). As described in NRC Inspection Report 05000369,370/2006007, this concerned a failure to follow procedures during performance of a TS required PT for ND pump 1B. Specifically, steps in completed procedure PT/1/A/4204/001B were signed by an individual that was not qualified to sign the steps, the individual signed steps as completed that were not performed, and the individual designated a non-conditional step as being not applicable (N/A). On January 30, 2007, the NRC Office of Investigations (OI) completed an investigation pertaining to URI 05000369/2006007-04. Based on a review of the OI investigation, the NRC determined that a violation of NRC requirements occurred. The Severity Level IV violation was cited in an OI letter dated July 17, 2007 (NOTICE OF VIOLATION, EA-07- 130). For administrative purposes this violation (VIO) is designated as VIO 05000369/ 2007005-05, Failure to Follow Procedure During Residual Heat Removal Pump 1B Performance Test. The inspectors have reviewed the licensees August 16, 2007, response to the Notice of Violation and subsequent corrective actions. Because the results of PT/1/A/4204/001B were not affected by the procedural non-compliance and appropriate corrective actions have been taken, URI 05000369/2006007-01 and VIO 05000369/2007005-05 are closed.
05000369/FIN-2008008-01	2007Q4	Mcguire McGuire	Failure to Take Adequate Corrective Action for Implementation of Safety-Related RN Strainer Backwash)	On December 31, 2007, the U.S. Nuclear Regulatory Commission (NRC) completed a quarterly integrated inspection at your McGuire Nuclear Station. The inspection findings were documented in NRC Inspection Report 05000369/2007005 and 5000370/2007005, which was issued on January 31, 2008. Section 4OA3 of that report identified Unresolved Item (URI) 05000369,370/2007005-03, which concerned a failure to take adequate corrective action related to implementation of a safetyrelated service water (RN) strainer backwash system. Subsequent to additional inspection, the performance deficiency was identified as a failure to correct a significant condition adverse to quality identified in 2002 related to macro-fouling of the RN strainers, in that the corrective action failed to ensure that the design and licensing basis required ability for manual strainer backwash could be maintained even during accident conditions. More specifically, the 2003 plant modification that was implemented to address the macro-fouling concern (i.e., upgrade and reclassification of the strainer backwash function to safety-related): (1) utilized non-safetyrelated instrument air (VI) to maintain each RN pumps strainer backwash discharge valve open, but did not provide a means to manually open (or bypass) the discharge valve to support backwash operations upon a loss of VI; and (2) did not account for the impact on timely operator response from higher strainer macro-fouling rates (whether from fish or other potential sources) and expected (nuisance) strainer delta pressure alarms (without fouling) at the onset of high RN flow events (i.e., safety injection and loss of VI). As such, between 2003 and August 7, 2007, there was a lack of reasonable assurance that the RN system would be able to perform its safety-related function upon a safety injection or loss of VI event during periods of macrofouling This finding was assessed based on the best available information, including influential assumptions, using the applicable Significance Determination Process (SDP) and was preliminarily determined to be a Greater Than Green Finding. Enclosed is a summary of the SDP Phase 3 analysis. It reflects a finding of greater than very low safety significance because, in the event of a loss of RN backwash capability, either through response to a safety injection signal or a loss of VI, that occurs during a time of high fouling potential, there was a lack of reasonable assurance that the RN system would have been capable of performing its safetyrelated function. The significance of the finding is influenced by uncertainties in the calculation for assumptions made for the initiating event frequency for the loss of VI, and for the calculated exposure time for the periods of fouling. Because of these uncertainties, the result was classified as Greater Than Green. The finding does not represent a current safety concern because temporary modifications and appropriate procedural changes have been made to address periods of potential macro-fouling. The finding is also an apparent violation (AV) of 10 CFR 50 Appendix B Criterion XVI, Corrective Action, for the failure to correct a significant condition adverse to quality related to macro-fouling of the RN strainers. This apparent violation (identified as AV 05000369,370/2008008-01, Failure to Take Adequate Corrective Action for Implementation of Safety-Related RN Strainer Backwash) is being considered for escalated enforcement action in accordance with the NRC Enforcement Policy. Accordingly, for administrative purposes, URI 05000369,370/2007005-03 is considered closed.
05000369/FIN-2007005-02	2007Q4	Mcguire McGuire	Failure to Control a LOCKED-HIGH Radiation Area Barrier	No findings of significance were identified. However, on September 30, 2006, during a refueling outage on Unit 2, a radiation protection technician left the reactor head inspection stand locked-high radiation area (LHRA) barrier unlocked and unguarded from approximately 5:05 to 5:21 a.m., contrary to the requirements of Technical Specification 5.7.2. Dose rates as high as 10 rad/hr at 30 cm and 4 rad/hr general area were present inside the reactor head stand LHRA. This event was appropriately reported to the NRC as an occupational radiation safety cornerstone performance indicator occurrence. The licensees root cause failure analysis report determined the root cause to be that the radiation protection technician did not perform the procedure steps as written (to ensure the barrier was secure) due to poor work practices and failure to validate assumptions; however, the inspectors determined that additional review and discussion of the details of the event, the licensees root cause analysis, and the implemented corrective actions were required to characterize the significance of the event. Therefore, this issue is identified as URI 05000370/2007005-02, Failure to Control a Locked-High Radiation Area Barrier. This issue is in the CAP as PIP M-06- 4479.
05000369/FIN-2007005-03	2007Q4	Mcguire McGuire	Failure to Take Adequate Corrective Action for Implementations of SAFETY-RELATED Rn Strainer Backwash	On August 6, 2007, the licensee identified that the procedures for performing a manual backwash of the nuclear service water strainers directed operators to use a nonseismically qualified, non-safety related air system to manipulate the valves required for the manual backwash function. This unqualified air system cannot be relied upon to function during a DBA. These backwash procedures were written as part of a 2003 plant modification (MGMM-14403) to upgrade and reclassify the manual RN filtering and backwash functions to safety-related, in response to NRC concerns (PIP M-02-2427). The concerns were that the changed environment of Lake Norman had caused seasonal macro-fouling of the strainers from increased concentrations of Alewife fish during late July and early August. The basis for reclassification was to ensure proper operation of the strainer in the event that significant fouling from these fish occurred. This modification also failed to identify reliance on other non-safety instrumentation and components for performing safety-related backwashes, including the UFSAR-credited differential pressure instrument. The reliance on non-safety-related systems to perform the safety-related manual backwash function was not recognized during the modification. The inspectors found that the licensee has continued to evaluate this issue after the LER was submitted. These continuing evaluations address such aspects as what happens inside the strainer, at what point does flow become less than what is needed as identified in design calculations, and what actions would operators take that might impact when the minimum flow point is reached. This finding involves the inability to perform a safety-related manual backwash of nuclear service water strainers due to reliance on non-safety systems and motive force to provide the backwash function. Without manual backwash capability during macrofouling season, these strainers could become permanently fouled, which could prevent the nuclear service water system from performing its intended safety function. This issue is more than minor because it affects the availability, reliability, and capability of the nuclear service water system and is related to the design control, protection from external factors (loss of heat sink), and procedure quality attributes of the mitigating systems cornerstone. This issue is unresolved pending NRC review of the licensees evaluations of past strainer operability, including the licensees classification of significant fouling periods and the engineering analyses of the fish clogging effects on the strainer. This item is identified as Unresolved Item (URI) 05000369,370/2007005-03 Failure to Take Adequate Corrective Action for Implementation of Safety-Related RN Strainer Backwash. This issue is in the licensees corrective action program as PIP M- 07-4313.
05000369/FIN-2007003-02	2007Q2	Mcguire McGuire	Reactor Vessel Head Lift Practices Related to Design and Licensing Basis	Based on a review of the documents listed in the Attachment of this report related to heavy load lifts of the reactor vessel head and discussions with licensee personnel, the inspectors identified the following issues: The licensee could not demonstrate that a risk assessment had been performed for the increase in risk associated with the lifting and setting of the reactor vessel head. The licensee could not demonstrate that their reactor vessel head lifts, which lift the head to approximately 38 feet over the irradiated fuel in the reactor vessel, were bounded by any design calculations which evaluated the drop of the head through air onto the reactor vessel, upper internals, and irradiated fuel. The licensee could not demonstrate that their procedures for the reactor vessel head removal and installation, ever limited their head lifts to the bounds contained in an August 17, 1984 letter sent to the NRC concerning a load drop analysis for reactor vessel head lifts. The licensee could not demonstrate that their UFSAR had been adequately updated to reflect information and analyses provided to the NRC as the result of all generic communications relative to their resolution of heavy loads issues. The licensee issued PIPs M-07-3099, M-07-3410, and G-07-0449 to address the above issues. A complex maintenance plan was issued for the most recent head installation that occurred on May 18, 2007, to manage risk. A multi-site team has been formed to address the issues above and to work with vendors to determine whether an alternative design and licensing basis exists that bounds past practices. The issues identified above are greater than minor because they are associated with the design control attribute of the Initiating Events Cornerstone and affected the cornerstone objective to limit the likelihood of those events that upset plant stability and challenge critical safety functions during shutdown. The issues are also greater than minor because the failure to update the UFSAR could have an impact on safety and may require a license amendment for resolution. These issues are unresolved pending the completion of the licensees investigation into whether an alternative design and licensing basis exists and whether reactor vessel head lifts were ever performed within the bounds of that basis. They are identified as URI 05000369,370/2007003-02, Reactor Vessel Head Lift Practices Related to Design and Licensing Basis
05000369/FIN-2007003-01	2007Q2	Mcguire McGuire	Debris in Unit 1 ECCS Sump	While reviewing PIP M-07-1609, the inspectors discovered that on March 17, 2007, the licensee found fire wrap/blanket in the Unit 1 Train B ECCS sump. The blanket was folded over multiple times and partially stuffed into the annular area between the ECCS suction pipe penetration bellows and the bellows guard pipe. The licensee performed an extent of condition inspection for train A, and found a similar fire wrap/blanket in the same respective location. In addition, the PIP indicated that there was other additional material found inside the screened sump structure, behind the suction piping supports, which included non-transportable debris (i.e., two 16P nails, 12\\\" drill bit, 3\\\" cutting wheel, 12\\\" nut, and a 4\\\" partial welding rod stick) and transportable debris (i.e., 3\\\"x6\\\" paper tag dated 3/13/04, a cigarette butt, an empty cigarette package, and several small pieces (<2\\\"x3\\\") of aged, friable duct-tape). The licensee performed several evaluations with regard to this issue during the inspection period which were documented in a Materials Lab Report, dated April 30, 2007, and a Reportability Support Evaluation for PIP M-07-1609, dated May 21, 2007. The Materials Lab Report was included as Attachment 1 to the Reportability Support Evaluation, a thermal expansion analysis was included as Attachment 2, and Attachment 3 was a February 21, 2007, test on ECCS Throttle Valve Duct Tape Flow Testing, which was conducted as part of an evaluation for the Unit 2 duct tape issue documented in Unresolved Item (URI) 05000370/2006005-01. The licensee plans to conduct a more refined throttle valve test for the Unit 2 duct tape issue in the near future. The Unit 1 ECCS debris in the sump issue is greater than minor because if left uncorrected the transportable debris could have had a detrimental affect on the availability and reliability of both trains of the Unit 1 ECCS when called upon during an accident. Specifically, the debris had the potential to have detrimental effects on the high pressure and low pressure ECCS recirculation function. This issue is unresolved pending completion of the NRC review of the licensees reportability evaluation and the results of the more refined duct tape testing. It is identified as URI 05000369/2007003- 01, Debris in the Unit 1 ECCS Sump.
05000261/FIN-2007003-01	2007Q2	Robinson	Emergency Core Cooling Sump Piping Foreign Material	No findings of significance were identified. However, during a refueling outage on April 22, 2007, the licensee used a remote video camera to visually inspect the two suction lines between the ECCS sump and RHR pumps A and B. Inspection of the first line revealed a piece of wire approximately 30 inches long, and inspection of the second line revealed a stainless steel insulation band and other smaller items of metallic debris. These items were immediately removed. The licensee has not completed their engineering evaluations at the end of the inspection period. The inspectors determined that additional inspections are required to determine whether and to what extent the subject debris could have affected safety functions during a postulated event that includes recirculation flow from the ECCS sump. Therefore, this issue is identified as URI 05000261/2007003-01, Emergency Core Cooling Sump Piping Foreign Material. This issue is in the CAP as AR 230613.
05000321/FIN-2007002-01	2007Q1	Hatch	Manual Operator Actions Allowed Due to an Inadequate 10 CFR 50.59 Evaluation	An NRC-identified Severity Level IV non-cited violation (NCV) was identified for an inadequate 10 CFR 50.59 evaluation. The licensee proceduralized manual actions in place of automatic actions to close the door to an adjacent office to maintain the main control room (MCR) pressure boundary operable without prior NRC review and approval. Violations of 10 CFR 50.59 potentially impact the NRCs ability to perform its regulatory function. Therefore, this finding was subject to traditional enforcement. This finding was determined to be of very low safety significance because the door only impacted the radiological response of the MCR, the door was capable of being closed, and procedural guidance was in place to close the door. In accordance with the NRC Enforcement Policy, Supplement I.D.5, this finding was determined to be a Severity Level IV violation. This violation has been entered into the licensees corrective action program as Condition Report (CR) 2006112331.
05000327/FIN-2006005-02	2006Q4	Sequoyah	Inability 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
05000321/FIN-2006004-01	2006Q3	Hatch	Failure to Report Safety Relief Valve Test Results Outside Technical Specification Limits	An NRC-identified non-cited violation of 10 CFR 50.73 a2iB was identified for failure to report past conditions prohibited by plant Technical Specifications TS. The inspectors determined that, during the most recent operating cycle for both Units 1 and 2, several main steam safetyrelief valves exceeded the TS lift setting tolerance. These represented reportable events. This finding was evaluated using the traditional enforcement process because the failure to accurately report events has the potential to impact the NRCs ability to perform its regulatory function. This finding was determined to be a Severity Level IV violation based on Supplement I of the NRC Enforcement Policy.
05000369/FIN-2006007-01	2006Q2	Mcguire McGuire	Failure to Follow Procedure During ND Pump 1B Performance Test	The team identified an unresolved item (URI) for failure to follow procedures during performance of a TS required PT for ND pump 1B. Specifically, steps in completed procedure PT/1/A/4204/001B were signed by an individual that was not qualified to sign the steps, the individual signed steps as completed which were not performed, and the individual designated a non-conditional step as being not applicable (N/A). This item is unresolved pending further NRC review of the circumstances surrounding these examples of failure to follow procedures.Analysis: Failure to follow procedures PT/1/A/4204/001B and OMP 4-1 is a performance deficiency. This finding is related to the procedure quality attribute of the mitigating systems cornerstone and affects the objective of ensuring the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences. The failure to follow procedures did not affect the pump performance during the periodic test and there was no actual loss of safety function. Enforcement: 10 CFR 50, Appendix B, Criterion V, Instructions, Procedures, and Drawings, requires that activities affecting quality shall be prescribed by documented instructions, procedures, or drawings, of a type appropriate to the circumstances and shall be accomplished in accordance with these instructions, procedures, or drawings. Procedure OMP 4-1, Use of Operating and Periodic Test Procedures, Revision 28 stated that procedure users shall be qualified to perform the task, initial or check each step after the action is completed, and shall not N/A any non-conditional step, unless approved. Contrary to the above, during the performance of PT/1/A/4204/001B, 1B ND Pump Performance Test, Revision 72, on October 2, 2005, the procedure user signed certain steps without having the appropriate qualifications, initialed steps as being completed that were not performed, and marked N/A on a non-conditional step without documented approval. This condition has existed since October 2, 2005. The licensee entered this item into the corrective action program as PIP M-06-1462. This finding is identified as URI 05000369/2006007-01, Failure to Follow Procedure During ND Pump 1B Performance Test. This finding is unresolved pending further NRC review of the circumstances surrounding these examples of failure to follow procedures.
05000250/FIN-2006002-02	2006Q1	Turkey Point	Failure of MOV-3-744B to open when demanded on March 7, 2006	The inspectors observed portions of the plant shutdown and cooldown in accordance with FPL procedure 3-GOP-305, Hot Standby to Cold Shutdown, to verify that cooldown restrictions and similar procedural requirements were followed. During the shutdown, while attempting to place the B loop of residual heat removal into shutdown cooling, the residual heat removal system injection valve, 3-MOV-744B, did not open when demanded. The licensee then placed the A loop of RHR in service and began an investigation to determine the cause of the failure. The initial results of the investigation identified that the motor had failed. However, at the end of the inspection period, additional inspection was needed to resolve this issue. Therefore, pending additional inspection this will remain open as unresolved item URI 50- 250/2006-02-02, Failure of MOV-3-744B to open when demanded on March 7, 2006.
05000327/FIN-2005011-01	2005Q4	Sequoyah	Reliance on 20-foot Separation Zones for Fire Protection in Unit 1 480V Board Room 1B	The 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.
05000327/FIN-2005011-02	2005Q4	Sequoyah	Unprotected Power Cables to Vital Inverters in Unit 1 480V Board Room 1B	The 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-2005011-04	2005Q4	Sequoyah	Appendix R Operator Action to Throttle AFW in Main Steam Valve Vault Room	The 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-2005011-05	2005Q4	Sequoyah	Reliance on Local Manual Operator Actions for Appendix R Fires	The 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.
05000302/FIN-2004009-04	2005Q1	Crystal River	No Cooling to Reactor Coolant Pump Seals for up to Eight Hours	The team noted that the licensees Appendix R Fire Study and post-fire SSD procedures relied on reactor coolant pump (RCP) seals remaining intact, without leaking, without cooling for up to eight hours. Because this practice differed significantly from general industry RCP seal design capabilities, this issue is unresolved pending further NRC review of the technical basis for acceptability. Crystal River 3 had Byron-Jackson (now Flowserve) N-9000 seal cartridges installed in the RCPs. Further, the licensee had a vendor analysis titled RCP N-9000 Seal Appendix R Evaluation supporting the ability of the seals to go without any cooling for up to eight hours without failing or leaking. Because RCP seals are not generally designed for eight hours without cooling and without failing or leaking, the team determined that NRC review of the vendor analysis was necessary. This issue is identified as URI 05000302/2004009-004, No Cooling to Reactor Coolant Pump Seals for up to Eight Hours.
05000302/FIN-2004009-02	2005Q1	Crystal River	Single Failure Vulnerability of Common Electrical Protection and Metering Circuits	The team identified a violation of 10 CFR 50, Appendix B, Criterion III, Design Control, for installing and modifying electrical protection and monitoring circuits that did not meet the general design criteria for single active failures. A common electrical protection and metering circuit was installed such that a single active failure of a component in the circuit could trip and lock out all feeder breakers to both 4160V ES busses, resulting in a loss of all safety-related alternating current power. This finding was an immediate safety concern and the licensee made modifications to correct the nonconforming condition before the inspection team left the site. This finding is unresolved pending the completion of a significance determination. The finding is greater than minor because it is associated with the design control and equipment performance attributes of the reactor safety mitigating systems cornerstone. The finding adversely affects the objectives of availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences.