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| Quarter | Site | Title | Description | |
|---|---|---|---|---|
| 05000237/FIN-2008004-01 | 2008Q3 | Dresden | Failure to Provide an Adequate Procedure for Several Instrument Maintenance Surveillance Tests | The inspectors identified a NCV of Technical Specification (TS) 5.4.1 for the failure to provide an adequate procedure for the verification of correct installation and restoration of equipment during instrument maintenance surveillance tests in June and August 2008. As part of the corrective actions, the licensee included a task to identify affected instrument surveillance procedures and generate a work down curve for revising the affected procedures. Using IMC 0612, Appendix E, Examples of Minor Violations, issued on September 20, 2007, the inspectors determined that there were no similar examples to this finding in Appendix E. The inspectors referenced IMC 0612, Appendix B, Issue Screening, dated September 20, 2007. The inspectors determined that the finding was more than minor based on Section 3, (2), If left uncorrected would the finding become a more significant safety concern. The inspectors determined that the failure to perform an independent verification that a testing configuration had been returned to normal could result in the inability of a system or component to perform its function which would be a more significant safety concern. No systems had been incorrectly returned to service as a result of the inadequate procedure and, therefore, this violation had very low safety significance. The inspectors did not identify a cross-cutting issue for this finding that was separate from the finding itself for inadequate procedures. (Section 1R22) |
| 05000237/FIN-2008004-02 | 2008Q3 | Dresden | Repetitive Contaminated Water Spills in the Unit 2 Reactor Building | A performance deficiency for the spill of contaminated water and the unexpected spread of contamination on multiple occasions was self revealed by additional spills in August 2008. The failure to clear a blockage in the floor drain system in a timely manner caused the Unit 2 reactor building floor drains to overflow at least four times in nine months. No violation of regulatory requirements occurred. As part of the corrective actions, the licensee created WO 1160517, Operations Venting Core Spray Leads to Contaminated Area, to hydrolaze the floor drains in the Unit 2 reactor building in order to clear the blockage. Using the guidance contained in IMC 0612, Power Reactor Inspection Reports. Appendix B, Issue Disposition Screening, dated September 20, 2007, the inspectors determined that the finding could be reasonably viewed as a precursor to a significant event. The inspectors evaluated the finding using IMC 0609, Appendix M, Significance Determination Process Using Qualitative Criteria, dated December 22, 2006. The inspectors used a worst-case bounding evaluation that assumed the loss of various pieces of equipment in the plant. As a result, the risk significance of the inspection finding was determined to be of very low safety significance (Green). The inspectors determined that this issue affected the cross-cutting area of Problem Identification and Resolution because the licensee failed to take corrective actions to address an adverse trend in a timely manner. P.1.(d) (Section 4OA2) |
| 05000237/FIN-2008004-03 | 2008Q3 | Dresden | Licensee-Identified Violation | Technical Specification 3.1.6.B required that if nine or more operable control rods were not in compliance with the analyzed rod pattern sequence then rod withdrawal was to be suspended and the reactor mode switch was to be placed in shutdown. This requirement only applied to the Unit when it was less than 10 percent reactor power. On January 15, 2008, a Dresden Nuclear Power Station Qualified Nuclear Engineer identified that the control rod sequence used for the startup of Unit 2 following the refueling outage in November 2007 did not comply with the control rod drop accident analysis, and that the startup performed on November 19, 2007, did not comply with TS 3.1.6, Rod Pattern Control, for about five and one-half hours. Nine or more control rods were not in compliance with the analyzed rod pattern and reactor mode switch was not placed in shutdown. Non-compliance with a TS is a more than minor performance deficiency. Later review by Westinghouse identified that the rod sequence used by the licensee was acceptable for use in the rod drop analysis. Therefore this issue was of very low safety significance (Green). The licensee documented this issue in IR 722652. The inspectors reviewed corrective actions in IR 722652 and LER 237/2008-001 and no additional findings of significance were identified. |
| 05000237/FIN-2008004-04 | 2008Q3 | Dresden | Licensee-Identified Violation | On May 23, 2008, the licensee identified that a flexible connector was disconnected on a Halon bottle for the Auxiliary Electrical Equipment Room (AEER) fire suppression system. The licensee concluded that the halon system was last worked on April 24, 2008, under WO 01083261-01, Perform DFPS 4195-01, Halon System Operability, and the system connections were not properly tightened. This was a violation of TS 5.4.1. The licensee declared the system inoperable, reconnected the flexible connector thereby restoring operability, and placed the issue into their corrective action system in IR 779061, AEER Halon Pilot Hose Not Connected. The licensee performed a prompt investigation and a human performance investigation of the incident in addition to reviewing historic operability. The inspectors reviewed the licensees assessment of the functional impact of the disconnection upon the Halon system. The flexible connector from the solenoid pilot valve to port B of the manual-pneumatic actuator was disconnected at the solenoid pilot valve for the #1 pilot bottle for the initial discharge bank of Halon bottles. The disconnection would have prevented actuation of the solenoid pilot valve for the #1 pilot bottle from pressurizing the pilot manifold. (Manual actuation using the pull lever on the bottle would not have been affected.) The Halon system had two pilot bottles for initial discharge bank and the redundant pilot bottle was not affected. Consequently, upon receiving a signal to discharge, the redundant pilot bottle would have pressurized the pilot manifold line resulting in the contents of the all of the Halon bottles within the initial discharge bank being discharged. The licensee evaluated the potential for back leakage through the disconnected flexible connector depressurizing the pilot manifold line. The inspectors concurred with the licensees assessment that reduction in pressure of the pilot line due to the disconnection would have been minimal and that discharge of the Halon bottles (due to actuation of the redundant pilot cylinder) would not have been prevented. The inspectors noted that the back leakage flow path had a 1/32 inch restriction in comparison to the 3/16 inch flexible connectors used for pressurizing the pilot manifold. In accordance with IMC 0609, Significance Determination Process, Attachment 0609.04, Phase 1 - Initial Screening and Characterization of Findings, Table 3b the inspectors determined the disconnection degraded the fire protection defense-in-depth strategies. Therefore, screening under IMC 0609, Appendix F, Fire Protection Significance Determination Process, was required. The inspectors concluded that the disconnection represented a low degradation because, although there would have been a loss of redundancy, the Halon system would have functioned. As such, the issue screened to Green under Task 1.3.1, Step 1, of IMC 0609. |
| 05000237/FIN-2008005-03 | 2008Q4 | Dresden | Reportability for Inadvertent Rod Withdrawal | On November 3, 2008, Unit 3 was in Day 1 of the D3R020 refueling outage and the operations department was performing multiple tasks to support removing systems from service. The plant was shutdown with all control rods fully inserted into the core. One of the scheduled tasks was alignment of the control rod drive system in preparation for hydro-lazing the Unit 3 scram discharge volume. Non-licensed operators (NLOs) were in the process of isolating the control rod drive (CRD) mechanisms per a clearance order that directed using Procedure DOP 0500-05, Discharging of CRD Accumulators with Mode Switch in Shutdown or Refuel, when a control rod drift alarm was received in the control room at 10:42 a.m. Over the next few minutes, multiple rod position indication system (RPIS) indications went to green double-dashes (- -), indicating the control rod had slightly inserted beyond the full-in position. The reactor operators notified the control room supervisor and the shift manager. Ensuing discussion between these individuals and the operations staff supervisor came to the decision that instrument maintenance individuals in the auxiliary electrical equipment room (AEER) had probably caused the interruption in the RPIS indications. The operations staff supervisor was dispatched to the AEER to determine if the work there had disrupted the RPIS indication. Over about 17 minutes, seven control rod indications sequentially went from full-in to over-travel in. Four of the indications settled back to indicated full-in; however, three control rod indications drifted out from the full-in position (D-7 to position 06, E-7 to position 18, and E-6 to position 16). Until the three control rods drifted out, the reactor operators had not recognized that the seven affected control rods were actually moving and had not taken any action to prevent possible outward rod motion. The control room operators then entered Technical Specification (TS) 3.1.1, Condition D, Procedure DOA 0300-12, Mispositioned Control Rod, and referenced DGA 7, Unexpected Reactivity Addition, stopped multiple clearance orders involving the CRDs, verified no work was in progress on RPIS and notified the qualified nuclear engineer. The operators subsequently discovered the control rods had drifted due to increasing differential pressure between the CRDs and the reactor when NLOs had sequentially shut the insert riser isolation valve (101) and the withdraw riser isolation valve (102) to each CRD, isolating the related CRD. Operations department staff returned the three control rods to full-in by opening the related 101 valve until the control rod moved fully in to the overtravel position. When the related 101 valve was re-shut, each of the control rods settled to the full-in position. Inspector interviews revealed that the control room operators were not in communication with the NLOs who were isolating CRDs and did not try to establish communication via the plant announcing system when the indications started to change; did not believe the indication that control rods were actually moving; did not take actions to prevent outward motion (SCRAM the plant or go to shutdown on the Mode switch) before the three rods started to drift out; and had not discussed the possibility of a reactivity addition or control rod motion during the pre-job briefing. The licensee completed a Prompt Investigation Report on this event (AR 839678) and determined that industry operating experience (OE) existed specific to this event. Institute of Nuclear Power Operations (INPO) Significant Event Notice (SEN) 264, Unplanned BWR Control Rod Withdrawals While Shutdown, dated April 10, 2007, detailed historical events at several BWRs between 1978 and 2000 where single or multiple control rods unexpectedly moved out of the core without a deliberate withdrawal signal. The reactor had become critical at two plants, one of which had the reactor vessel head removed. The key lessons from SEN 264 were: 1. The isolation of multiple hydraulic control units (HCUs) with the control rod drive pumps in operation can cause higher-than-normal cooling and exhaust header pressures that may be a precursor to inadvertent rod motion (insert or withdraw) if a sufficient number of HCUs are not in service or if alternate system flow paths are not established. 2. Station Procedures should specify the minimum number of HCUs to be kept in service while the control rod drive pump is in service, to prevent inadvertent control rod movement when HCUs are being isolated and restored, particularly during outage conditions. 3. Reactor operators should monitor control rod drive system pressures, rod positions, and alarms during outages when the system is being manipulated to identify changing conditions that could lead to inadvertent control rod movement. 4. Personnel who operate valves to isolate and restore HCUs should be aware that their actions directly affect control rod drive system pressures that can lead to inadvertent control rod movement. When SEN 264 was originally received at Dresden, the HCU system manager and an operations technical superintendent performed the subject matter expert review of the SEN under Action Tracking Item (ATI) 616696-04. A qualified nuclear engineer also reviewed SEN 264; however, he stated that it was unlikely that he would have reviewed any operations procedures independent of the one procedure identified in ATI 616696-04 because he is not an operations procedures expert. The licensee incorporated the SEN 264 information into the 300 Series procedure on the control rod drive system, specifically, to monitor the cooling and exhaust header pressures every 10 HCUs after 50 HCUs had been isolated. This change was intended to alert operators to the potential increase in pressure in the CRD system so that operators could take actions to reduce pressure and avoid an unplanned control rod withdrawal event similar to SEN 264. However, the inspectors determined the licensee had not reviewed all procedures that isolated the HCUs. Specifically, the information was not entered into the 500 Series procedures that applied to the reactor protection system. During the performance of the clearance order to isolate the control rod drive mechanisms on November 3, 2008, the non-licensed operators were using a 500 series procedure, Procedure DOP 500-05, Discharging CRD Accumulators with Mode Switch in Shutdown or Refuel, Revision 5, when the last three control rods, (D-7, E-7, and E-6) drifted out of the core to positions 06, 18, and 16. The inspectors reviewed the event and determined that more than three control rods could have moved out and that the control rods would have continued moving out continuously until the 102 valve to the related HCU was closed. Therefore, the inspectors concluded it was possible that the three (or more) control rods could have moved to full out position 48. The licensee analyzed the shutdown margin for the reactor for the following possible conditions: • The actual position of the three rods at the actual temperature and xenon conditions -- the reactor was 4.5 percent subcritical. • Three drifted rods at 48, actual temperature and xenon conditions 3.1 percent subcritical. • Cold conditions (actual rod positions, 68F, and zero xenon) 1 percent subcritical. • Design shutdown margin (actual rod pattern plus 1 rod full out, 68F, and zero xenon) critical. However, the licensee had not analyzed the shutdown margin for the three drifted rods if they were full out at cold conditions. After the inspectors requested the results of those conditions, the licensees analysis showed that the reactor would have been critical under those conditions. The temperature of the reactor coolant, the amount of xenon in the core, the order in which the control rod mechanisms were isolated, the pressure in the control rod drive system, and the time between when the inset valve was shut and the withdraw valve was shut were key parameters for this event. The procedure in use, DOP 500-05, did not appear to control any of these parameters. The inspectors were concerned that under different conditions the inadvertent, unplanned control rod movement could have caused the reactor to go critical. Additionally, the inspectors were concerned that the licensee had not reported the event to the NRC in accordance with 10 CFR 50.72. In discussions with the licensee on this topic, the inspectors learned that the licensee interpreted the guidance in NUREG 10-22, Event Reporting Guidelines 10 CFR 50.72 and 50.73, to not require immediate notification because the reactor remained sub-critical at the time of discovery. Subsequent to these discussions, the licensee made a 50.72 report to the NRC on November 18, 2008. In order to resolve a difference of opinion regarding whether this event should have been promptly reported under 50.72, the inspectors planned to request assistance from the Office of Nuclear Reactor Regulation (NRR). Pending additional clarification from NRR, the inspectors considered the reporting of this event to be an URI |
| 05000237/FIN-2009002-01 | 2009Q1 | Dresden | Failure to Develop a Pre-Fire Plan for Fire Zone 18.6 | The inspectors identified an NCV of the Dresden Nuclear Power Station Renewed Facility Operating License having very low safety significance for the licensees failure to develop a pre-fire plan for Fire Zone 18.6. This issue was entered into the licensees CAP as issue reports 873977 and 875688. The licensees corrective actions included the development of a pre-fire plan for Fire Zone 18.6. The finding was more than minor because it involved the Mitigating Systems attribute of protection against external factors (i.e., fire), where the failure to develop a pre-fire plan for Fire Zone 18.6 could have adversely impacted the fire brigades ability to fight a fire. The inspectors completed a Phase 1 significance determination of this issue using IMC 0609, Significance Determination Process, Appendix A, Attachment 0609.04. However, as discussed by Attachment 0609.04, issues related to performance of the fire brigade are not included in IMC 0609, Appendix F, Fire Protection SDP, and require management review. The finding was reviewed by NRC management, and was determined to be a finding of very low safety significance because no safe shutdown equipment was located in this fire zone. The inspectors determined that this issue also affected the cross-cutting area of Problem Identification and Resolution (e.g., corrective action program) because the licensee failed to thoroughly evaluate the problem addressed in NCV 05000237/2008008-02; 05000249/2008008-02, Failure to Develop a Pre-fire Plan for Fire Zone 18.6, such that appropriate corrective actions to address safety issues and adverse trends were not taken in a timely manner, commensurate with their safety significance and complexity, (P.1(d)) |
| 05000237/FIN-2009002-02 | 2009Q1 | Dresden | Failure to Implement and Maintain in Effect All Provision of the Approved Fire Protection Program as Described in the UFSAR | A self-revealed NCV of the Dresden Nuclear Power Station Renewed Facility Operating License having very low safety significance was identified for the licensees failure to implement and maintain in effect all provisions of the approved Fire Protection Program as described in the Updated Final Safety Analysis Report (UFSAR). Specifically, the licensee failed to ensure that the floor penetrations to Fire Zone 2.0 were sealed as described in the Fire Hazards Analysis. Licensee corrective actions included revising the Fire Hazard Analysis and sealing the floor penetrations. The finding was more than minor because it involved the Mitigating Systems attribute of protection against external factors (i.e., flood hazard, fire) and impacted the Mitigating Systems objective to ensure availability, reliability, and capability of systems that respond to initiating events (i.e., flood hazard, fire) to prevent undesirable consequences. The inspectors performed a Phase 1 qualitative screening and the finding screened to very low safety significance. The inspectors determined that because the modifications took place in the 1985 to 1986 timeframe, the performance deficiency is not reflective of current licensee performance and therefore no cross-cutting area was affected |
| 05000237/FIN-2009002-03 | 2009Q1 | Dresden | Failure to Ensure the Control of the Design Basis Was Correctly Translated Into Station Procedures | The inspectors identified a NCV of 10 CFR 50, Appendix B, Criterion III, Design Control, of very low safety significance, for the failure to ensure that the control of the design basis was correctly translated into station procedures. The procedures used to control the temporary placement of 480V heaters in safety-related areas did not meet the station procedural requirements for a temporary configuration change. The violation was placed into the licensees corrective action program (CAP) in Issue Report (IR) 876126. The licensees corrective actions included planning to change all the station procedures that control the installation and removal of temporary heaters. Using the guidance contained in IMC 0612, Power Reactor Inspection Reports, Appendix B, Issue Disposition Screening, dated December 4, 2008, the inspectors determined that the finding was more than minor because, if left uncorrected, the performance deficiency had the potential to lead to a more significant safety concern. The inspectors evaluated the finding using IMC 0609, Appendix M, Significance Determination Process Using Qualitative Criteria, dated December 22, 2006. Per IMC 0609, Appendix M, a bounding quantitative and/or qualitative (i.e., worst case analysis) was performed. The resultant risk significance of the inspection finding was determined to be of very low safety significance and is determined to be Green. The inspectors determined that this issue also affected the cross-cutting area of Problem Identification and Resolution because the licensee failed to take corrective actions to address a safety issue in a timely manner, (P.1(d)) |
| 05000237/FIN-2009002-04 | 2009Q1 | Dresden | Failure to Take Corrective Actions to Replace a Degraded Valve in a Timely Manner | The inspectors identified an NCV of 10 CFR 50, Appendix B, Criterion XVI, Corrective Action, for the failure to correct degraded safety-related equipment in a timely manner. A degraded 4-way solenoid valve for the reactor building ventilation damper 2-5741B actuator was not replaced during the work window that started on January 5, 2009. The solenoid valve failed on January 13, 2009, when it was called upon during a reactor building ventilation isolation. The violation was placed into the licensees corrective action program in IR 877591. The licensees corrective action included replacing all the 4-way solenoid valves in the actuators for all the Unit 2 and Unit 3 reactor building ventilation secondary containment isolation boundary dampers. Using the guidance contained in IMC 0612, Power Reactor Inspection Reports, Appendix B, Issue Disposition Screening, dated December 4, 2008, the inspectors determined that the finding was more than minor because it was associated with the Reactor Safety Barrier Integrity Cornerstone objective of maintaining the functionality of the secondary containment. The inspectors evaluated the finding using IMC 0609, Attachment 0609.04, dated January 10, 2008. Per Table 4a, under Containment Barrier, question 1, Does the finding only represent a degradation of the radiological barrier function provided for the ... Standby Gas Treatment System, the inspectors answered, YES. The secondary containment isolation valves isolate the secondary containment to ensure the effectiveness of the Standby Gas Treatment System. Therefore the finding was determined to be Green. The inspectors determined that this issue also affected the cross-cutting area of Problem Identification and Resolution, (P.1(c)). |
| 05000237/FIN-2009002-05 | 2009Q1 | Dresden | Operator Performed an Incorrect Response to an Unexpected Alarm in the Control Room | On January 13, 2009, a Finding with no violation of regulatory requirements was self-revealed when an operator performed an incorrect response to an unexpected alarm in the control room that resulted in a reactor building ventilation isolation and a standby gas treatment system actuation. This action required entry into TS 3.6.4.1 Limiting Condition of Operation, Action A for reactor building low differential pressure. The finding was more than minor because it impacted the structures, systems, and components attribute of the Barrier Integrity Cornerstone objective. The finding was of very low safety significance because it impacted the reactor building differential pressure for a time period of less than one hour. The finding was placed into the licensees CAP as IR 866445. As an immediate corrective action, the individual was temporarily removed from licensed shift duties and no manipulation of any equipment in the plant or the control room was allowed without a peer check until January 18, 2009. The inspectors also concluded that this finding affected the cross-cutting issue of Human Performance (Personnel) because the operator failed to utilize human performance error prevention techniques, (H.4(a)) |
| 05000237/FIN-2009002-06 | 2009Q1 | Dresden | Failure to Declare Primary Containment Isolation Valve Inoperable and Take Required Actions | A self-revealed NCV of Dresden Station Improved Technical Specification (TS) 3.6.1.3, Primary Containment Isolation Valves (PCIVs), of very low safety significance was identified for the failure to declare primary containment isolation valve 3-3702 inoperable and take actions in accordance with the requirements of TS 3.6.1.3 required action A. The licensee generated IR 837675 and IR 839009 to address this issue. Corrective actions included: the initiation of a training request to re-enforce with Operations personnel the potential operability issues when light indications are not functioning properly, and the revision of Operations procedures to include guidance to alert users that a failed or flickering indication light associated with a motor operated valve may indicate problems that could affect valve operation, and that valve operability must be verified. The finding was more than minor because it impacted the Barrier Integrity objective to provide reasonable assurance that physical design barriers (i.e., containment) protect the public from radionuclide releases caused by accidents or events. The inspectors completed a Phase 1 significance determination of this issue using IMC 0609, Attachment 0609.04, Phase 1 Initial Screening and Characterization of Findings, The inspectors answered NO to all questions in the Containment Barrier column of Table 4a, therefore the finding screened as Green (i.e., very low safety significance). The inspectors determined that this finding also affected the cross-cutting area of Human Performance, resources aspect (H.2(c)) because the licensee failed to provide complete, accurate and up-to-date procedures |
| 05000237/FIN-2009002-07 | 2009Q1 | Dresden | Licensee-Identified Violation | Technical Specification 5.4.1 requires that written procedures be established and implemented for activities provided in Regulatory Guide 1.33, Revision 2, Appendix A, February 1978. Procedures specified in Regulatory Guide 1.33 include procedures for performing maintenance. Contrary to this requirement, on August 16, 2008, operations personnel unsuccessfully attempted to pump the Unit 3 drywell floor drain sump to partially satisfy TS Surveillance Requirement 3.4.4.1. The licensee identified later that the valve plug had separated from the stem in the Drywell Floor Drain Sump Containment Isolation Valve 3-2001-1005. The licensee determined that the maintenance procedure governing valve replacement was inadequate which resulted in higher than desired actuator output and seating forces. The inspectors reviewed the licensees corrective actions. The inspectors had no issues with the licensees corrective actions and determined that they were completed or had an acceptable time table for completion. This incident was identified in the licensees corrective action program as Issue Report 807914 and documented in LER 249/2008-001-00, Unit 3 Drywell Floor Drain Sump Monitoring System Declared Inoperable. This violation was determined to be of very low safety significance because the containment isolation valve failed in a closed condition ensuring its ability to perform a containment isolation function |
| 05000237/FIN-2009002-08 | 2009Q1 | Dresden | Licensee-Identified Violation | Technical Specification 5.4.1 requires that written procedures be established and implemented for activities provided in Regulatory Guide 1.33, Revision 2, Appendix A, February 1978. Procedures specified in Regulatory Guide 1.33 include radiation protection procedures for radiation surveys and contamination control which are provided by licensee procedure RP-AA-503, Unconditional Release Survey Method, Revision 1. That procedure requires that material or equipment that is unconditionally released outside the radiologically controlled area (RCA) have no detectable licensed radioactive material. Contrary to this requirement, on February 3, 2009, a small strap was unconditionally released outside the RCA within the licensees protected area but later that same day found to have low levels (10,000 disintegrations per minute) of fixed contamination. This incident was identified in the licensees corrective action program as Issue Report 875773. This violation was determined to be of very low safety significance because the uncontrolled strap did not result in any dose to a member of the public in the restricted or controlled areas |
| 05000237/FIN-2009002-09 | 2009Q1 | Dresden | Licensee-Identified Violation | The Licenses for Units 2 and 3 require that the licensee follow their fire protection program. Fire protection program requirements are identified in the Technical Requirement Manual. Technical Requirements Manual, Section 3.7.k, Condition B, states in part that the Auxiliary Electrical Equipment Room (AEER) halon system, including the extended discharge cylinders shall be operable and if not then a dedicated fire watch shall be established within 1 hour. Contrary to the above, on October 29, 2008, the licensee identified that all of the AEER halon fire suppression extended discharge cylinders were completely discharged. The licensee concluded that the cylinders had been in this condition since October 23, 2008, based on a trend recording of a downward spike in room temperature caused by the discharge. The inspectors and the NRC Region III senior reactor analyst (SRA) used IMC 0609 Appendix F, Fire Protection Significance Determination Process to evaluate the significance of the finding. The finding category of Fixed Fire Protection Systems was assigned because the function of the automatic Halon suppression system for the AEER was degraded. Since only the extended release portion of the system was affected and the initial release was fully functional, a moderate degradation rating for the finding was used. The NRC assumed that the design concentration could be achieved but could not be maintained for sufficient time to ensure fire extinguishment. The condition existed for 6 days. The Significance Determination Process (SDP) uses a generic duration factor of 0.1 if the duration of the degradation is between 3 and 30 days. Since the exact duration was known to be 6 days, the SRA calculated an actual duration factor of 0.016 (6/365 days). The generic fire area frequency for a cable spreading room with other electrical equipment is 6.0E-3/yr. The change in Core Damage Frequency (CDF) calculated in the phase 1 SDP is determined by multiplying the duration factor by the generic fire area frequency which is estimated to be 9.6E-5/yr. Since this value is greater than 1E-5, the screening criterion for moderate degradation findings, a phase 2 evaluation was required. In step 2.1 of the SDP, the identified safe shutdown path for a fire in the AEER was evaluated. Because the finding does not affect the safe shutdown path, it can be credited. After reviewing the licensees safe shutdown analysis, the SRA determined that safe shutdown after a fire in the AEER would require local operator actions. Therefore, a safe shutdown unavailability factor of 0.1 was applied. The delta CDF was recalculated by multiplying the duration factor, fire frequency, and safe shutdown path unavailability factor and was determined to be 9.6E-6/yr. This result was conservative because it does not include any credit for manual fire suppression using the installed carbon dioxide system which was unaffected by the finding. Since this delta CDF was less than the screening criterion of 1E-5, the finding was determined to be of very low safety significance and screened to Green in step 2.1.4. The inspectors had no issues with the licensees corrective actions and determined that they were completed or had an acceptable time table for completion |
| 05000237/FIN-2009004-01 | 2009Q3 | Dresden | Significance of Potentially Submerged Safety and Non-safety Related Low Voltage Power and Control Power Cables | The inspectors identified an unresolved item regarding the regulatory requirements associated with potentially submerged safety and nonsafety-related low voltage power and control power cables. The inspectors walked down the 2/3 cribhouse, the Unit 3 cable tunnel, and the cable tunnels that lead from Units 2 and 3 out to the 345 kv offsite power switchyard to determine if cables were submerged. The inspectors determined that low voltage (600 v) nonsafety-related control power cables that lead from the power block out to the 345 kv offsite power switchyard are routinely submerged. The inspectors also determined that the safety-related power cables for the U3 diesel generator cooling water pump were installed in a condition that was routinely submerged. Whether or not these cables were designed for submergence and whether or not low voltage cables were subject to premature failure due to submergence is considered an unresolved item pending further NRC review. |
| 05000237/FIN-2009004-02 | 2009Q3 | Dresden | Failure to Identify and Replace CR120A Relays as Recommended by GE SIL 229 Supplement 1 | A finding of very low safety significance was identified by NRC Inspectors for the licensees failure to identify and replace several CR120A relays as recommended by GE SIL 229 Supplement 1. Specifically, the licensee failed to replace several CR120A relays associated with primary containment valve isolation logic which eventually resulted in a partial Group 2 logic isolation event. The licensee entered this issue into the corrective action program (CAP) as Issue Report 923691. The licensee plans to replace these CR120A relays. There was no enforcement action associated with this finding. This finding was determined to be more than minor because it was associated with the Equipment Performance attribute of the Initiating Events Cornerstone and affected the cornerstones objective to limit the frequency of those events that upset plant stability and challenge critical safety functions during power operations. The relay failure caused an unplanned partial Group II primary containment isolation that impacted plant operations for several days. This issue was determined to be of very low safety significance since it did not contribute to both a reactor scram and loss of a mitigating function when evaluated as a Transient Initiator. |
| 05000237/FIN-2009004-03 | 2009Q3 | Dresden | Low Pressure Coolant Injection Pump Mechanical Seals | The inspectors identified an unresolved item regarding the non-safety related classification of the Unit 2 and Unit 3 low pressure coolant injection pump (LPCI) mechanical seals. Description: On July 6, 2009, the 2A LPCI pump seal was replaced under Work Order 548808-01. A non-safety related seal was used. The licensee performed an evaluation (D-93-003-0858-00) in 1993 stating that it was acceptable to use a non-safety related seal in the LPCI and core spray pumps. The inspectors questioned the evaluation because of the very limited explanation and justification for the classification downgrade. For example, the licensee stated that a seal failure in any form would only result in minor seal leakage with no technical justification for that assumption. The licensee performed another evaluation EC 376561, Safety Classification of LPCI Pump Shaft Seals. The inspectors reviewed this evaluation and found it lacking in technical justification also. The licensee has stated that a pump seal failure will only result in minor leakage with no justification other than it has never had more than minor leakage in the past. The inspectors planned to review this technical explanation. Whether or not the LPCI and core spray pumps on both units are in conformance with regulatory requirements is considered an unresolved item pending further NRC review. |
| 05000237/FIN-2009004-04 | 2009Q3 | Dresden | Inspector Identified Control Room Alarm Isolation Valve Out-of-Position | The inspectors identified an unresolved item regarding the reason why valve 2-1501-42A, U2 low pressure coolant injection (LPCI) A pump gland leak-off, was found out-of-position. Description: On September 24, 2009, the inspectors identified that the 2-1501-42A valve was out-of-position. The inspectors were reviewing the 2A LPCI pump seal leak-off configuration as part of an evaluation of the mechanical seal safety classification. The inspectors reported the valve position to shift management and operations department personnel verified the valve was not in the position described in DOP 2-1500-M1, LPCI System Mechanical Checklist, Revision 39. This issue was documented in Issue Report (IR) 969490, LPCI Gland Seal Leak-off Isolation Found Closed. With the valve closed instead of open a control room alarm (902-3 C-6) for LPCI pump seal leakage would not have alarmed for the 2A LPCI pump had the seal failed during operation. On July 6, 2009, the 2A LPCI pump seal was replaced under Work Order 548808-01. The issue is considered an unresolved item pending NRC review of the licensees evaluation of the valve position versus the requirements of DOP 2-1500-M1 |
| 05000237/FIN-2009004-05 | 2009Q3 | Dresden | Failure to Follow Technical Specification 5.5.2 Implementing Procedures | The inspectors identified several examples of failure to follow the procedures that implemented Technical Specification (TS) 5.5.2, Primary Coolant Sources Outside Containment. These failures were determined to represent a Green finding and a non-cited violation. Planned corrective actions associated with this violation included, but were not limited to: a revision to DTP 09, Leak Detection and Reduction Program, to restore commitments made to the NRC; changes to the work control program to ensure that leaks identified by the Leakage Reduction Program are given a high priority; assignment of a program owner; revising operating surveillances to ensure they meet the requirements of TS 5.5.2; initiating a training program for operations and engineering personnel on TS 5.5.2; and developing an administrative limit on emergency core cooling system leakage outside the primary containment. The finding was determined to be more than minor because the finding, if left uncorrected, would become a more significant safety concern. Specifically, the failure to track, trend, and repair leakage outside primary containment could lead to exceeding radiation exposure limits in the event of an accident. This finding was determined to have very low safety significance because the actual emergency core cooling system leakage outside the primary containment was low. This finding had a cross-cutting aspect in the area of Human Performance, Work Practices because the licensee did not effectively communicate expectations regarding procedural compliance with regard to TS 5.5.2, Primary Coolant Sources Outside Containment. Specifically, licensee personnel failed to follow several procedural requirements because they were unaware of the requirements. H.4(b) |
| 05000237/FIN-2009004-06 | 2009Q3 | Dresden | Impact of Chimney Flow Monitor Degradation on Timely and Accurate EAL Classification | The inspectors identified an Unresolved Item (URI) concerning the impact of inaccurate, non-conservative chimney flow monitor values on the licensees ability to make timely and accurate emergency action level (EAL) classifications for radiological effluent releases, as provided in procedure EP-AA-1004, Radiological Emergency Plan Annex for Dresden Nuclear Power Station. Discussion: In March 2008, the licensee identified that the chimney flow transmitter was restricted due to fouling of its flow elements. The licensees investigation disclosed that the flow transmitter had provided inaccurate indications since April 2004. The flow indicated by the transmitter was approximately 40 percent lower than the actual chimney flow. The chimney flow data provided by the transmitter is used as a parameter to quantify gaseous effluents released to the environment. Chimney flow is also used to calculate the instantaneous noble gas concentrations released to the environment from the chimney to determine EAL classifications based on radiological effluents. As a result of the flow transmitter fouling, for a four year period beginning in 2004, gaseous effluents released through the chimney were non-conservatively calculated and reported. The inspectors reviewed the licensees revised effluent calculations and determined they were accurate and technically sound. While the original offsite dose determinations for 20042007 had been underestimated by as much as 40 percent, the corrected calculations showed that the un-assessed dose for each of those years was less than 1 percent of the 10 CFR Part 50, Appendix I, design objective. Consequently, the radiological impact of the problem was of minor safety-significance. The inspectors reviewed the actions taken by the licensee to correct the flow monitor degradation, and actions planned to address deficiencies with the calibration of the flow monitoring system and with the licensees surveillance program, which contributed to the extended duration of the problem. The issue remains under review by the NRC to determine the impact of the problem on the licensees emergency preparedness program for the timely and accurate declaration of EAL classifications consistent with the licensees procedures. The issue is categorized as an URI pending further NRC review |
| 05000237/FIN-2009004-07 | 2009Q3 | Dresden | Licensee-Identified Violation | 10 CFR 50.46(a)(3)(b)(1), Peak cladding temperature, requires that the calculated maximum fuel element cladding temperature shall not exceed 2200 F for the postulated loss-of-coolant accidents described within 10 CFR 50.46. Contrary to this requirement, from November 19, 2007 to April 24, 2008, the calculated peak cladding temperature for the Unit 2 Large Break Loss of Coolant Accident Analysis was 2230 F. This finding was entered into the licensees corrective action program as IR 767796. The licensee implemented an immediate corrective action that assigned an administrative 3 percent reduction (penalty) in the MAPLHGR Technical Specification core operating thermal limit to offset a non-conservative error identified in the calculation. This finding is of very low safety significance because the reactor core had been operating within the established 3 percent MAPLHGR administrative limit region since the reactor was restarted from the November 2007 refueling outage. |
| 05000237/FIN-2009004-08 | 2009Q3 | Dresden | Licensee-Identified Violation | Technical Specification 5.4.1 requires that written procedures be established and implemented for activities provided in Regulatory Guide 1.33, Revision 2, Appendix A, dated February 1978. Procedures specified in Regulatory Guide 1.33 include procedures for performing surveillance tests on the Standby Gas Treatment (SBGT) System which are provided by licensee procedure DOS 7500-02, SBGT System Surveillance and IST Test, Revision 46. Contrary to this requirement, on September 18, 2009, operations personnel failed to follow the instructions in procedure DOS 7500-02 to fill the 2/3 A SBGT loop seal as part of an in-service testing (IST) surveillance. Operations personnel misread step I.22 of DOS 7500-02 and failed to close an isolation valve associated with filling the 2/3 A train of SBGT loop seal. The valves had similar equipment part numbers (EPN), one was 2/3-7513A-500 and the other was 2/3-7513A-500TV. Step I.22 of DOS 7500-02 instructed the individual to close valve 2/3-7513-A-500. The individual did not question the fact that the valve thought to be correct (2/3-7513-A-500TV) was already in that position. The failure to close the isolation valve associated with this task may have resulted in introducing water into the 2/3 A SBGT filter which could make the system inoperable. The inspectors determined that this issue was more than minor because the licensee had to declare the 2/3 A train of SBGT inoperable and take the system out-of-service to perform an inspection to verify that water was not introduced into the system. In addition, online risk changed to Yellow during this evolution. This incident was identified in the licensees corrective action program as Issue Report 966877. This finding was determined to be of very low safety significance because the inspections performed demonstrated that water was not introduced into the system. |
| 05000237/FIN-2009005-10 | 2009Q4 | Dresden | Electro-Hydraulic Control (EHC) Fluid Leaking From Stop Valve 3-5699-MSV4-FA Resulting in Forced Outage D3F49 | The inspectors identified an unresolved item regarding the regulatory requirements associated with the circumstances surrounding the Unit 3 turbine trip on On November 5, 2009, at 8:53 p.m., Unit 3 Control Room received the following alarm: 903-7 B-6, EHC (electro-hydraulic control) RESERVOIR LVL HI/LO (reference IR 989641) indicating a rate of change in the EHC reservoir at 1.3 in 100 hrs or greater. A non-licensed operator (NLO) was dispatched to stage a barrel of EHC fluid for addition. Preparations were made for a heater bay entry to look for leaks. A Unit 3 heater bay entry was made and it was determined that the Unit 3 Main Turbine Stop Valve (MSV) # 4 had an EHC leak from the fast-acting solenoid valve (3-5699-MSV4-FA). The leak was determined to be approximately 4-5 gallons of fluid per hour. A report from the field was that reservoir level had dropped about 1.1 in the last 12 hours. Between 12:50 a.m. and 3:43 a.m. on November 6, 2009, the licensee added two barrels of EHC fluid to the EHC reservoir. On November 6, 2009, between 9:00 a.m. and 2:00 p.m., licensee management conducted meetings regarding the repair of the leak on MSV #4. The plan called for starting to down power Unit 3 to 650 Mwe for a planned 3:00 p.m. entry into the heater bay to repair the valve. The decision to go to 650 Mwe was to reduce the dose rate in the area and extend stay time for the repair. At approximately 3:00 p.m., while staging for entry to repair the leak, Operations personnel informed the NLO, staged to isolate the oil supply to the leaking valve, that level in the EHC reservoir was dropping quickly, and requested the NLO to enter the pipeway as soon as possible. At approximately 3:05 p.m., the NLO observed oil spraying profusely from the bottom area of #4 Main Stop Valve and the area of the solenoid that was going to be changed out. The NLO immediately contacted the control room to report what was observed and a decision was made to take the turbine offline. At 3:32 p.m., the Unit 3 Turbine was tripped. The licensee had not completed their root cause investigation by the end of the inspection period. The inspectors planned to review the root cause investigation to determine if there were any violations of NRC requirements and that appropriate corrective actions were applied. (URI 05000249/2009005-10 |
| 05000237/FIN-2010002-01 | 2010Q1 | Dresden | Failure to Record the Identity of Personnel Performing Post-Maintenance Tests | A finding of very low safety significance and associated NCV of 10 CFR Part 50, Appendix B, Criterion XVII, Quality Assurance Records, was identified by the inspectors for the licensees failure to record the identity of various personnel who performed seven post-maintenance tests (PMTs) related to Unit 3 EDG maintenance. Despite the PMTs being related to work on safety-related components, an activity affecting quality, neither the licensees procedure MA-AA-716-012, Post-Maintenance Testing, nor DAP 15-10, Post-Maintenance Testing Program, required the identity of the inspector or tester to be recorded. Completed corrective actions included adding PMT documentation requirements to DAP 15-10 and briefing individuals who perform PMTs. This finding was determined to be more than minor because the finding was similar to IMC 0612, Appendix E examples 1b since a portion of required records were irretrievably lost, and 2h since multiple examples were identified as failures to properly implement the same regulatory requirement. Following IMC 0612, Appendix B, it was apparent that this issue did not fall directly under a cornerstone and that incomplete information was recorded in the seven PMTs. Therefore, the Enforcement Policy was used to screen the severity in conjunction with the IMC 0612, Appendix E, Examples 1b and 2h. Since MA-AA-716-012, Post-Maintenance Testing, did not properly implement regulatory requirements, this finding has a cross-cutting aspect in the area of Human Performance, Resources because the licensee did not provide complete, accurate, and up-to-date procedures to plant personnel. H.2(c |
| 05000237/FIN-2010002-02 | 2010Q1 | Dresden | Failure to Follow Technical Specification 5.5.4 Implementing Procedure | The inspectors identified a finding of very low safety significance and associated Non-Cited Violation of Technical Specification 5.5.4 for the licensee failing to follow Step I.2.a and b of Procedure DOS 1500-08, Discharge of Containment Cooling Service Water (CCSW) From Low Pressure Coolant Injection (LPCI) Heat Exchanger (Hx) During CCSW Pump Operations, Revision 16. Specifically, the licensee failed to perform a tube leak test as required by DOS 1500-08 when activity exceeded 1.5E-6 microcuries/milliliter. The licensees corrective actions included a change to DOS 1500-08 to ensure personnel do not waive performance of the test procedure until tube leak checks are considered during non-routine samples of CCSW and revising the chemistry sampling procedure CY-DR-110-220, LPCI Service Water (CCSW) and Torus Water Sampling, to notify operations to evaluate performance of a tube leak check if activity exceeds 1.5E-6 microcuries/milliliter. The inspectors determined that the failure to perform a tube leak test or perform Calculated CCSW Sample Activity Limit and Canal Activity Calculations was contrary to DOS 1500-08, and was a performance deficiency. The finding was determined to be more than minor because the finding, if left uncorrected, would become a more significant safety concern. Specifically, had there been an actual LPCI Hx tube leak radioactivity could have been released. The inspectors determined the finding could be evaluated using the SDP in accordance with IMC 0609, Significance Determination Process, Attachment 0609.04, Phase 1 - Initial Screening and Characterization of Findings, Table 4a for the Containment Barrier Cornerstone. All four questions on this table were answered no. There was no actual degradation of the containment barrier. Therefore, the issue screened as having very low safety significance. This finding had a cross-cutting aspect in the area of Human Performance, Decision Making because the licensee did not demonstrate that the proposed action was safe in order to proceed rather than a requirement to demonstrate that it was unsafe in order to disapprove the action. Specifically, the licensee assumed the activity in the sample was coming from the floor drain system with no valid proof that was the case. H.1(b |
| 05000237/FIN-2010002-03 | 2010Q1 | Dresden | Failure to Meet Regulatory Commitment to Maintain Contingency Plans for Post-Accident Sampling | The inspectors identified a finding of very low safety significance for the failure to meet a regulatory commitment to maintain a contingency plan for obtaining highly radioactive samples of reactor coolant, the suppression pool, and drywell atmosphere for post-accident plant recovery planning. Specifically, the licensees contingency plan was not adequately maintained to ensure the High Radiation Sampling System (HRSS) functioned adequately or otherwise was demonstrated to be in a state of readiness to allow samples to be obtained within a two-week window. No violations of regulatory requirements were identified related to this finding. Corrective actions were being developed to ensure the licensees contingency plan commitments would be met. Those actions included a means to improve system ownership and establishment of an effective process for HRSS equipment maintenance and repair at a priority consistent with its intended use. The finding was more than minor because it impacted the facilities and equipment attribute of the Emergency Preparedness Cornerstone and adversely affected the cornerstone objective of ensuring capability to implement adequate measures to protect health and safety of the public in the event of a radiological emergency. Specifically, equipment intended to obtain highly radioactive samples that are used to assess reactor core condition as part of post-accident recovery activities was not demonstrated to be in a readiness condition consistent with the licensees contingency plan. The finding was determined to be of very low safety significance because it involved equipment, which supplements the licensees emergency plan for reentry and recovery activities as provided in the planning standard of 10 CFR 50.47(b)(8), and represented a planning standard problem associated with demonstrating functional readiness of that equipment. The finding was determined to be associated with a cross-cutting aspect in the area of human performance in the resources component, in that, the licensee failed to ensure that equipment to support its emergency plan was functional or otherwise was demonstrated to meet a defined status of operational readiness. H.2(d |
| 05000237/FIN-2010002-04 | 2010Q1 | Dresden | Significance of Potentially Submerged Safety and Nonsafetyrelated Low Voltage Power and Control Power Cables | The inspectors identified a finding of very low safety significance with an associated Non-Cited Violation of 10 CFR Part 50, Appendix B, Criterion III, Design Control. Specifically, licensee personnel failed to maintain safety-related cables in underground manholes from becoming repeatedly submerged, which resulted in subjecting the cables to an environment for which they were not qualified. As corrective action, the licensee generated work order (WO) 01271108 on September 24, 2009, to remove the seals on the conduit which contained the cables and which kept water from draining out of the conduit. This issue was entered into the licensees corrective action program as Issue Report (IR) 975308. The finding was determined to be more than minor because the finding was associated with the Mitigating Systems Cornerstone attribute of equipment performance and affected the cornerstone objective of ensuring the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences. The finding was of very low safety significance because it was a qualification deficiency that did not result in a loss of operability. The inspectors concluded that there was not a cross-cutting issue associated with this violation |
| 05000237/FIN-2010002-05 | 2010Q1 | Dresden | Electro-Hydraulic Control (EHC) Fluid Leaking From Stop Valve 3-5699-MSV4-FA Resulting in Forced Outage D3F49 | The failure of the Unit 3 Main Turbine Stop Valve (MSV) # 4 fast acting solenoid valve on November 6, 2009, resulted in a self-revealed finding of very low safety significance. The licensee failed to use the correct o-rings and bolts when replacing the Unit 3 MSV #4 fast acting solenoid valve during the Unit 3 refueling outage in 2008 which led to the failure. The equipment was not safety-related. Therefore, this finding did not result in a violation of regulatory requirements. The licensees corrective actions included revising maintenance procedure DEP 5600-01, Main Turbine Valve Solenoid and Servo Maintenance, to incorporate the actions described in GE Technical Information Letter 1594. The bolts on the U3 and U2 solenoid valves were replaced. The licensee did not determine that the o-rings were defective until after both this Unit 3 forced outage and the Unit 2 November 2009 refueling outage were complete. Therefore, one corrective action was to write a work order to change the o-rings on the solenoids for both units. In addition, corrective actions were put in place to address weaknesses in the evaluation of Operating Experience. The licensee addressed this issue in the corrective action program under Issue Reports 899829 and 989733. The inspectors determined that the use of o-rings, GE part number U472X000B906, in U3 turbine control valve solenoids, was contrary to Vendor Technical Information Program Binder D1180, General Electric Steam Turbine Generator (GEK5551), Tab 8, GE drawing 115D2402 (Revision 12), and GE Technical Information Letter (TIL) 1594, dated November 30, 2007, which required the use of o-rings, GE part number U472X000BS906, and was a performance deficiency. The finding was determined to be more than minor because the finding was associated with the Initiating Events Cornerstone attribute of procedure quality and affected the cornerstone objective of limiting the likelihood of those events that upset plant stability. The inspectors determined the finding could be evaluated using the SDP in accordance with IMC 0609, Significance Determination Process, Attachment 0609.04, Phase 1 - Initial Screening and Characterization of Findings, Table 4a, for the Initiating Events Cornerstone. The electro-hydraulic control leakage caused by one or more failed o-rings could have resulted in a turbine trip and reactor scram. However, the failure would not affect mitigating equipment or functions so the finding screened as having very low safety significance. This finding had a cross-cutting aspect in the area of Problem Identification and Resolution, Operating Experience because the licensee did not implement and institutionalize Operating Experience through changes to station processes, procedures, equipment, and training programs. P.2(b |
| 05000237/FIN-2010002-06 | 2010Q1 | Dresden | Licensee-Identified Violation | As noted in Section 4OA3.2 of this report, in 2009, the licensee discovered that changes had been inappropriately made to the 2B reactor recirculation pump discharge valve above seat drain line. Title 10 CFR 50.59(d)(1) requires the licensee to maintain records of changes in the facility, of changes in procedures, and of tests and experiments made pursuant to 50.59(c). Contrary to this requirement, on November 6, 2003, the licensee discovered that the configuration of the above seat drain line for the discharge valve of the 2B Reactor Recirculation pump, which comprises part of the reactor pressure boundary, had been previously modified so that it did not match the piping and instrumentation drawing (P&ID). The licensee could not locate any records that described the scope or date of the change, nor could they locate an evaluation that provided the basis for the determination that the change did not require a license amendment. This change resulted in the line not meeting the requirements of ASME NB3671.3 for Class 1 piping. The configuration of the above seat drain depicted on the P&ID showed a drain line piped to the equipment drain sump with two normally closed manual isolation valves. The configuration in which the above seat drain line was found during the 2003 refueling outage was a drain line with one closed valve and a threaded cap, which did not meet the requirements of ASME NB3671.3 for Class 1 piping. Issue Report 185073 was written, and a second isolation valve and a threaded cap were added to the drain line during the 2003 refueling outage to conform to ASME requirements. The P&ID was also updated to reflect the change. The finding associated with this violation is of very low safety significance (green) because it would not have likely resulted in exceeding the Technical Specification limit for Reactor Coolant System leakage and would not have affected other mitigating systems. Therefore, this would constitute a Severity Level IV violation per the NRC Enforcement Policy, Supplement I, Section D.5 |
| 05000237/FIN-2010002-07 | 2010Q1 | Dresden | Licensee-Identified Violation | The Code of Federal Regulations, Title 10, Part 50, Appendix B, Criterion III, Design Control, states, in part, Measures shall be established to assure that ... the design basis, as defined in 50.2 and as specified in the license application, for those structures, systems, and components to which this appendix applies are correctly translated into specifications, drawings, procedures, and instructions. These measures shall include provisions to assure that appropriate quality standards are specified and included in design documents and that deviations from such standards are controlled. Electrical Standard IEEE-279-1968, Proposed IEEE Criteria for Nuclear Power Plant Protection Systems, required, in part, that the reactor protection system (RPS) was designed, such that, the system was not susceptible to a single point vulnerability. On October 30,2009, the licensee identified that the RPS pressure switches PS 2-0504-A, B, C, and D all shared a common sensing line with a single isolation valve, which created a single point vulnerability for the turbine stop valve closure (RPS function 8) and turbine control valve fast closure - trip oil pressure low (RPS function 9) reactor scram functions. This condition had existed since original construction. The inspectors reviewed the licensees corrective actions. The inspectors had no issues with the licensees corrective actions and determined that they were completed for Unit 2 and had an acceptable time table for completion of Unit 3. This incident was identified in the licensees corrective action program as Issue Reports 986676 and 996586, and documented in LER 237/2009-007-00, Reactor Protection System Nonconformance to a Design Standard. This violation was determined to be of very low safety significance because the safety function of the reactor protection system was supported by existing procedure guidance in the event the sensing line failed or was inadvertently isolated; therefore, this condition resulted in RPS functions 8 and 9 being operable, but nonconforming |
| 05000237/FIN-2010002-08 | 2010Q1 | Dresden | Licensee-Identified Violation | Title 10 CFR Part 50, Appendix B, Criterion III, Design Control, requires that design changes, including field changes, shall be subject to design control measures commensurate with those applied to the original design and be approved by the organization that performed the original design unless the applicant designates another responsible organization. Contrary to this requirement, on November 3, 2009, it was identified that changes had been made, either intentionally or unintentionally, to the design of the plant by the removal of several Unit 2 core spray instrument piping supports, for an indeterminate period of time, without the application of appropriate design control measures. This finding was entered into the licensees corrective action program as IR 1002474. The licensees corrective actions included: restoration of the supports to the original design configuration; creation of a preventive maintenance activity to walk down piping supports prior to the drywell closeout; and an action to walkdown the Unit 3 drywell to verify all supports are connected and tight. The inspectors used Table 4b of IMC 0609.04, Phase 1 Initial Screening and Characterization of Findings to evaluate the significance of the finding. The finding was determined to involve the degradation of equipment specifically designed to mitigate a seismic event. The impact of the finding was that a seismic event could have resulted in the failure of the core spray dp line which would cause a seismically-induced small loss of coolant accident (LOCA) event with the possible unavailability of the B core spray train. The finding screened as potentially risk significant using the screening criteria of Table 4b. The RIII Senior Risk Analyst (SRA) performed a phase 3 SDP evaluation of the finding using the Dresden Standardized Plant Analysis Risk (SPAR) Model and the Risk Assessment of Operational Events Handbook, Volume 2 External Events. The SRA used the seismic initiating event frequency for Dresden (4.58E-04/yr) from the handbook and assumed that any seismic event would cause the failure of the core spray dp line and result in a small LOCA. A conditional core damage probability was estimated using the SPAR model by assuming a small LOCA event occurred simultaneous with a loss of offsite power and the unavailability of the B core spray train. The seismic initiating event frequency was combined with the estimated conditional core damage probability to estimate the delta CDF. The delta CDF calculated was less than 1E-7/yr, which is a finding of very low safety significance (Green). The dominant core damage sequences involved a seismically-induced small LOCA followed by the failure of both high and low pressure injection |
| 05000237/FIN-2010002-09 | 2010Q1 | Dresden | Licensee-Identified Violation | The licensee identified a finding of very low safety significance and associated Non-Cited Violation (NCV) of 10 CFR 50.54(t), Conditions of Licenses, for the failure to complete an independent review of all program elements of the emergency preparedness program. The independent assessment did not evaluate and document the adequacy of the interfaces with State and local governments at an interval not to exceed 12 months for all groups. Specifically, Quality Assurances assessment failed to evaluate the adequacy of interface with Will County in 2008. The licensee entered the issue in their corrective action program as AR-00889346 and all required audits were conducted in 2009 (Grundy, Kendal, Will, and the State of Illinois and Indiana). The deficiency was screened using the Emergency Preparedness SDP and determined to be more than minor because the finding adversely affected the EP Cornerstone objective. The failure to conduct the audit to evaluate the effectiveness of the EP program had the attribute associated with Offsite EP; specifically, the evaluation of the working relationship between the offsite and onsite emergency response organizations and programs. The inspector evaluated the finding using with IMC 0609, Appendix B, Sheet I, Failure to Comply flowchart. The audit program was noncompliant with a regulatory requirement not involving an EP planning standard or a risk significant planning standard; therefore, the finding was determined to be of very low safety significance (Green) |
| 05000237/FIN-2010004-01 | 2010Q3 | Dresden | Failure to Address NRC Concerns Regarding a Reactor Building Closed Cooling Water (RBCCW) Line Break in the Unit 3 Reactor Building | During a walkdown of the Unit 2 and Unit 3 reactor buildings the inspectors identified: That there were RBCCW pipes directly above the bermed areas surrounding the safety-related busses 23-1, 24-1, 33-1, and 34-1. If those pipes were to fail the bermed area around the busses would hold water in potentially resulting in the failure of power to all the low pressure ECCS pumps The inspectors identified that on Unit 3 there was only one hole (not several) in the floor inside the bermed area around busses 33-1 and 34-1 and that hole had a one and onehalf inch lip around it which was not notched. This configuration did not appear to be evaluated at the time the SER was written. The licensee performed an evaluation after the inspectors brought this condition to their attention. The review of the licensees evaluation is an unresolved item. (URI 05000237/2010004-01; 05000249/2010004-01) |
| 05000237/FIN-2010004-02 | 2010Q3 | Dresden | Failure to Seal Holes in the Floor Above the Emergency Core Cooling System (ECCS) Corner Rooms | During a walkdown of the Unit 2 and Unit 3 reactor buildings the inspectors identified: That there were holes in the floor on both units, which would allow flood water to bypass the berms around the stairways to the ECCS corner rooms. The holes in the floor could also potentially result in a loss of all ECCS pumps. In regard to the first observation, the inspectors reviewed a letter from the NRC to Commonwealth Edison (the licensee) dated August 20, 1982. The subject was, SEP (Systematic Evaluation Program) Topic III-5.B, Pipe Break Outside Containment - Dresden Nuclear Power Station Unit 2. The enclosure to the letter was the NRCs Safety Evaluation Report (SER) for SEP Topic III-5.B. In the safety evaluation, the NRC reviewed the licensees response to a previous NRC concern about the failure of the RBCCW piping above the 23-1 and 24-1 switchgear on Unit 2. The licensee responded that there were several holes in the floor inside the bermed area around busses 23-1 and 24-1. The largest hole had a one and one-half inch lip around it. The licensee stated that the lip would be notched and that the holes would be sufficient to let the water drain before it could get high enough to impact the safety-related busses. There was no mention of Unit 3 in the safety evaluation In regard to the second observation, the inspectors reviewed DR PSA-012, Internal Flood Evaluation Summary and Notebook, dated May 2009. This document supported the licensees probabilistic risk assessment, but was not part of the licensing basis. This document stated that the berms around the ECCS corner room stairs were credited in the internal flooding analysis. A review of the licensing basis to determine the design requirements of the ECCS corner room stairway berms was an unresolved item. (URI 05000237/2010004-02; 05000249/2010004-02) |
| 05000237/FIN-2010004-03 | 2010Q3 | Dresden | Installation of Nonconforming Material Into a Safety-Related System | The inspectors identified a finding of very low safety significance (Green) and associated NCV of 10 CFR Part 50, Appendix B, Criterion XV, Nonconforming Materials, Parts, or Components for the installation of a commercially dedicated part for use in a safety-related system which failed testing acceptance criteria on October 6, 2008. The licensees corrective actions included replacing the nonconforming material on November 11, 2009. The licensee made procedure changes to clarify the requirements for documentation of the technical justification of accepting discrepancies. The licensee entered this finding into the corrective action program as issue report (IR) 1068559. 2 Enclosure The finding was determined to be more than minor because the finding was similar to IMC 0612, Appendix E, Example 5c (dated August 11, 2009). The inspectors determined the finding could be evaluated using IMC 0609, Significance Determination Process, Attachment 0609.04, Phase 1 - Initial Screening and Characterization of Findings, Table 4a for the Barrier Integrity Cornerstone. The inspectors answered all four questions in Table 4a, No, therefore, the inspection finding screened as having very low safety significance. This finding has a cross-cutting aspect in the area of Human Performance - Decision Making. Specifically, there was a systematic process to ensure that discrepancies identified in the commercial grade dedication process were properly resolved, which was not followed. |
| 05000237/FIN-2010004-04 | 2010Q3 | Dresden | Failure to Identify and Correct Test Procedures to Assess the As-Found Trip Setpoint for Pressure Switches that Satisfy Technical Specification Functions | The inspectors identified a finding of very low safety significance (Green) and associated NCV of 10 CFR 50, Appendix B, Criterion XVI, Corrective Action, for the licensees failure to assure that conditions adverse to quality associated with preconditioning were promptly identified and corrected. The licensees corrective actions included actions for Engineering to evaluate all the Technical Specification functions that do not have test valves installed on their pressure switches and justify the potential unacceptable preconditioning as acceptable or take other actions as appropriate. The licensee entered this finding into the corrective action program as issue report (IR) 1120159. The finding was determined to be more than minor because it impacted the Mitigating Systems Cornerstone objective to ensure the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences. The inspectors did not identify any cross-cutting aspect associated with this finding. The inspectors evaluated the finding using IMC 0609, Significance Determination Process, Attachment 4, Phase 1 Initial Screening and Characterization of Findings. The inspectors answered No to all questions in the Mitigation System Cornerstone column of Table 4a, Characterization Worksheet for IE, MS, and BI Cornerstones, therefore, the finding screened as Green (very low safety significance). |
| 05000254/FIN-2009003-01 | 2009Q2 | Quad Cities | Inadequate Procedural Adherence During Unit 1 TIP PM Testing | A finding of very low safety significance and associated NCV of 10 CFR 50,Appendix B, Criterion V were self-revealed during the performance of the Unit 1traversing in core probe (TIP) modification testing on March 27, 2009. During modification testing, the #2 TIP retracted past the shielded position into the reactor building as a result of failure of test personnel to follow the test procedure. The control room received a, Rx Bldg Hi Radiation alarm from the local area radiation monitor. Radiation Protection personnel were on scene to evacuate personnel, track dose rates and to set up boundaries to prevent entry. There were no over exposures and no danger to the health and safety of other radiological workers as a result of this event. The inspectors determined that this finding has a cross-cutting aspect in the area of Human Performance, Work Practice - Expectations. The test coordinator position did not have a qualification program or documented management expectations for procedure adherence (H.4(b)).The inspectors determined that the failure of the test coordinator and instrument maintenance technicians to follow an approved procedure, TIC-2306, Automated TIP Control Unit (ATCU) Modification Test, was a performance deficiency and a finding. This finding was more than minor because if left uncorrected, this performance deficiency has the potential to lead to a more significant safety concern. The inspectors performed a Phase 1 SDP screening. Inspection Manual Chapter 0609, Attachment 4, Table 4a, Mitigating Systems Cornerstone questions were all answered no. Therefore the issue screened as Green, or very low safety significance |
| 05000254/FIN-2009003-02 | 2009Q2 | Quad Cities | Inadequate Procedural Guidance for Shutdown After Operating Basis Earthquake | A finding of very low safety significance and associated NCV were identified by NRC inspectors for an inadequate procedure, QCOA 0010-09, Earthquake. This procedure did not direct a shutdown in response to an earthquake event in excess of the operating basis earthquake threshold. Title 10 CFR 100 Appendix A, Section V(a)(2) states, If vibratory ground motion exceeding that of the Operating Basis Earthquake occurs, shutdown of the nuclear power plant will be required. Upon discovery, the licensee implemented immediate changes to QCOA 0010-09. This finding was more than minor because this performance deficiency challenged the Reactor Safety - Mitigating Systems Cornerstone attribute of procedure quality. The inspectors performed a Phase 1 SDP screening using IMC 0609, Attachment 4, Table 4a for the Mitigating Systems Cornerstone. All questions were answered no and the issue screened as Green, or very low safety significance. The inspectors determined that this finding did not have a cross-cutting aspect because this procedure has been in place since initial operation and this deficiency was determined to be a latent issue not readily identified through the procedure revision process |
| 05000254/FIN-2009003-03 | 2009Q2 | Quad Cities | 1/2 EDGCWP Failed to Swap Feeds | A finding of very low safety significance and a NCV of Quad Cities Unit 2Renewed License No. DPR-30 condition 3.B were self-revealed on April 10, 2009, when a previously unidentified blown fuse on the 1/2 emergency diesel generator (EDG) control power transfer circuit resulted in failure of the power supply for the associated diesel generator cooling water pump to transfer from Unit 1 to Unit 2. The fuse had apparently failed on March 25, 2009, when operators attempted to replace a burned out light bulb resulting in the diesel being inoperable for Unit 2 for 17 days. Although operators had indications that a circuit problem existed, timely actions were not initiated to ensure the unit continued to operate in accordance with Technical Specifications. Immediate corrective actions were accomplished on April 11, 2009, with replacement of the fuse and verification of circuit operability. Inspectors determined this finding to be cross-cutting in the area of Problem Identification and Resolution for the corrective action component because station personnel failed to investigate the non-conforming condition as directed by station procedures to adequately assess the impact on system operability and did not meet procedural requirements for evaluating operability (P.1(c)).The inspectors determined the finding was more than minor because the finding is associated with the Mitigating Systems Cornerstone attribute of equipment reliability and affected the cornerstone objective by impacting availability, reliability and capability of the Unit 2 emergency electrical supplies. Specifically, allowing the non-conforming condition on the 1/2 EDG to linger while performing maintenance activities on the Unit 2EDG challenged the availability of emergency AC power to Unit 2. The inspectors reviewed this finding in accordance with IMC 0609, Appendix A, Determining the Significance of Reactor Inspections Findings for At-Power Situations. The postulated accident where the 1/2 EDG would have failed its safety function is a loss of offsite power to both units followed by a loss of coolant accident on Unit 2. The Significance Determination Phase 2 performed by the residents and validated by the regional senior risk analyst showed risk significance much lower than the 1x10-6 threshold and therefore Green |
| 05000254/FIN-2009003-04 | 2009Q2 | Quad Cities | Trip of Unit 2 Fuel Pool Cooling Water Pumps During Scorpion Platform Removal | A finding of very low safety significance and NCV of 10 CFR 50.65 (a)(4) were self-revealed on May 11, 2009, when the licensee staff failed to manage water level in the spent fuel pool and associated skimmer surge tanks resulting in the Unit 2 fuel pool cooling pumps tripping off while removing the Scorpion platform from the Unit 1 reactor cavity. Immediate corrective actions for this event included refilling the skimmer surge tank and restarting the fuel pool cooling pumps to restore alternate decay heat removal. The inspectors determined that the failure to take adequate action to manage the risk associated with a maintenance activity with a potential to affect a key shutdown safety function was a performance deficiency and a finding. Inspectors determined that the finding was cross-cutting in the area of Human Performance Work Control for failure to coordinate work activities by incorporating actions to adequately address the need for work groups to communicate, coordinate and cooperate with each other during activities in which interdepartmental coordination is necessary to assure plant and human performance (H.3(b)).The inspectors determined the finding was more than minor because the failure to implement the management actions resulted in the critical safety function being degraded and the issue is associated with 10 CFR 50.65(a)(4) risk management. The inspectors performed a Phase 1 SDP evaluation and determined that the issue is Green because the Unit 1 pumps remained running with no issues during the event and plant operators were able to recover the Unit 2 cooling pumps before any discernable change in temperature occurred (answer to all questions of IMC 0609, Attachment 4, Table 4a, Mitigating Systems Cornerstone and Barrier Cornerstone were no and the issue screened as Green). Since the finding concerned risk management actions, the inspectors verified the finding was Green using IMC 0609, Appendix K flowcharts and validated that there was no change in risk thresholds as a result of the event |
| 05000254/FIN-2010003-01 | 2010Q2 | Quad Cities | Loss of Power to Freeze Seal Machines During OPDRV | A finding of very low safety significance and a NCV of 10 CFR Part 50.65(a)(4) was self-revealed on March 25, 2010, when operators turned off the electrical power to one of the two electrical freeze seal machines being used to apply a reactor coolant system boundary freeze seal. Specifically, plant staff did not identify the interrelation between the mechanical freeze seal activity and the operations electrical power switching activity during risk assessment activities, and, therefore, did not manage the work activities to prevent loss of power to the freeze seal machines providing the credited boundary to prevent draining the reactor vessel. Immediate corrective actions included restoration of power to the machine and reestablishment of freeze seal temperature The finding was determined to be more than minor because required risk management actions were not implemented. These risk management actions were associated with the Barrier Integrity Cornerstone attribute of Configuration Control and affected the cornerstone objective of providing reasonable assurance that the reactor coolant system boundary protects the public from radionuclide releases caused by accidents of events. The inspectors used IMC 0609, Significance Determination Process, Appendix G, Shutdown Operations - Significance Determination Process, Attachment 1, Shutdown Operations - Significance Determination Process: Phase 1 Operational Checklist for Both PWRs and BWRs, and determined that since key safety functions were maintained, the issue screened as Green. The inspectors identified a cross-cutting aspect associated with this finding in Human Performance - Resources, Procedures (H.2(c)). Although the engineering documentation evaluating the risk in using the electric freeze seal machine recommended the power supplies be protected by operations, this information was not translated into the freeze seal procedure, MA-AA-736-610, or the applicable work package. |
| 05000254/FIN-2010003-02 | 2010Q2 | Quad Cities | PCIS Relay Common Neutral Broken | A self-revealed finding of very low safety significance and a NCV of Technical Specification (TS) 5.4.1 was identified on April 8, 2010, when a Unit 2 Group III containment isolation signal was received during replacement of a primary containment isolation system (PCIS) relay as a result of a disconnected common neutral wire. Immediate corrective actions for this event included restoration of the reactor water cleanup system and rewiring for the PCIS relay to the proper configuration. The inspectors determined that the licensees failure to identify and provide instructions to mitigate the common neutral during the work planning process was a performance deficiency. The inspectors determined that this finding was cross-cutting in the area of Human Performance, Work Control, because the licensee failed to assess the impact of changes to the work scope during the maintenance activity when plant operating conditions had changed (H.3(b)) The inspectors determined the finding was more than minor because the performance deficiency impacted the Mitigating Systems Cornerstone attribute of Configuration Control for Operating Equipment Lineup to ensure the availability, reliability and capability of safety systems to respond to initiating events to prevent undesirable consequences. The inspectors performed a Phase 1 SDP evaluation. Using IMC 0609, Attachment 4, Table 4a, Mitigating Systems Cornerstone, all questions were answered No, and this finding screened as Green, or having a very low safety significance. |
| 05000254/FIN-2010003-03 | 2010Q2 | Quad Cities | Incorrect Wind Direction on NARS Form | A NRC-identified finding of very low safety significance and associated NCV of 10 CFR 50.47(b)(9) was identified for delayed corrective action without appropriate compensatory actions for a defective computer point that sends wind direction data to the plant parameter display system (PPDS). This defective computer point resulted in incorrect wind direction on a Nuclear Accident Reporting System (NARS) form transmitted to the State of Illinois as part of the declaration of an Unusual Event on May 19, 2010. Corrective actions included the restoration of the computer point for PPDS. Inspectors identified this performance deficiency had a cross-cutting aspect in Problem Identification and Reporting - Evaluation because although the non-functional computer point, R234, was identified in December 2009, the licensee failed to thoroughly evaluate, classify, and prioritize the condition of bad data from a computer point and assess how the condition affected PPDS (P.1(c)) This finding is more than minor because the performance deficiency matches an example of a Green finding from IMC 0609, Appendix B, Section 4.9, page B-20, Equipment or systems necessary for dose projection are not functional for longer than 24 hours from the TIME OF DISCOVERY without compensatory measures, or corrective actions are inadequate or delayed. Using IMC 0609, Appendix B, Sheet 1, Failure to Comply Flowchart, the performance deficiency screened as very low safety significance, or Green. |
| 05000254/FIN-2010003-04 | 2010Q2 | Quad Cities | MODE Change without Required RPS Instrument | A self-revealed finding of very low safety significance and a NCV of TS 3.0.4 was identified on April 14, 2010, when operators changed operating modes from MODE 2 to MODE 1 without having all required channels of the reactor protection system (RPS) turbine condenser vacuum-low scram function available prior to entering MODE 1. Immediate corrective actions for this event included restoration of the RPS channel. The inspectors determined that performing a MODE change from MODE 2 to MODE 1, without meeting the conditions of the limiting condition for operation (LCO) 3.0.4 or ensuring all required channels of the RPS turbine condenser vacuum-low scram function were available prior to entering MODE 1, was a performance deficiency. The inspectors determined that this finding was cross-cutting in the area of Problem Identification and Resolution - Evaluation, because the licensee failed to properly classify, prioritize, and evaluate the RPS functional operability of the degraded condenser vacuum indication (P.1(c)) The inspectors determined the finding was more than minor because the performance deficiency impacted the Mitigating Systems Cornerstone attribute of Configuration Control for Operating Equipment Lineup to ensure the availability, reliability, and capability of safety systems to respond to initiating events to prevent undesirable consequences. The inspectors performed a Phase 1 SDP evaluation. Using IMC 0609, Attachment 4, Table 4a, Mitigating Systems Cornerstone, all questions were answered No, and this finding screened as Green, or having a very low safety significance. |
| 05000254/FIN-2010004-01 | 2010Q3 | Quad Cities | Unit 2 Manual Scram | A self-revealed finding of very low safety significance (Green) and associated NCV of 10 CFR 50.65(a)(4) was identified for failure to assess and manage risks associated with maintenance activities. The applicable maintenance activities occurred between July 1, 2010, and August 17, 2010, on Unit 2. The inspectors determined that the licensees actions to assess and manage the risks associated with maintenance activities did not prevent a transient that upset plant stability, and were identified as a performance deficiency. The inspectors identified that this finding has a cross-cutting aspect because the licensee failed to verify the validity of the underlying assumptions supporting the work activity and identify possible unintended consequences (H.1(b)). The inspectors determined the finding was more than minor because the performance deficiency adversely affected the Initiating Events Cornerstone objective to limit the likelihood of events that upset plant stability and challenge critical safety functions during power operations. Using IMC 0609, Table 4a, Initiating Events Cornerstone column, Transient Initiators subsection; the question: Does the finding contribute to both the likelihood of a reactor trip AND that mitigation equipment or functions will not be available? was answered, No by the inspectors because all mitigating functions were available after the event. Therefore, this finding screens as Green, or very low safety significance. |
| 05000254/FIN-2010004-02 | 2010Q3 | Quad Cities | Licensee-Identified Violation | The following violation of very low safety significance (Green) was identified by the licensee and is a violation of NRC requirements which meets the criteria of Section 2.3.2 of the NRC Enforcement Policy for being dispositioned as an NCV. be implemented covering the procedures recommended in Regulatory Guide 1.33, Revision 2, Appendix A, February 1976. That revision of Regulatory Guide 1.33 states, in part, procedures for performing maintenance that can affect the performance of safety-related equipment should be properly pre-planned and performed in accordance with written procedures, documented instructions, or drawings appropriate to the circumstances. Contrary to the above, temporary equipment of sufficient size and mass to compromise the seismic qualification of safety-related switchgear was erected to support maintenance and left in place in violation of plant procedural requirements. Specifically, on August 23, 2010, the licensee identified that a Tele-tower, an adjustable work platform, had been installed to support work in the overhead on WO 715454, Cable Tray Cover Missing. After the work had been completed and the platform was documented as removed, a supervisor touring the plant, looking for potential problematic issues, identified that the platform was not removed, was in contact with the nearby safety-related switchgear 13, and, therefore, was not in compliance with MA-QC-716-026-1001, Seismic Housekeeping. The issue was documented in the licensees CAP as IR1104846, and the tower was removed as part of the immediate corrective actions. The finding was determined to be more than minor because documentation had been improperly completed after an apparently inaccurate verbal communication stating that the Tele-tower had been removed from the plant. As a result, no management controls were in place to limit the risk exposure for the safety-related equipment. Therefore, the procedure non-compliance adversely affected the External Events attribute of the Mitigating Events Cornerstone objective to ensure availability of systems that respond to initiating events to prevent undesirable consequences. The finding was determined to be of very low safety significance because all of the questions of IMC 0609, Table 4a for Mitigating Systems were answered No, and the finding is screened as Green. |
| 05000261/FIN-2011003-01 | 2011Q2 | Robinson | Rainstorm Results in Flooding of the Power Block | On May 27, 2011, a heavy rainstorm was not successfully managed by the sites engineered rainwater management features. This resulted in water run-off into the protected area, backing up of storm drains and water intrusion into the power block, Auxiliary Building and other support buildings. Additional review by the NRC is required following the completion of the licensee\\\'s root cause investigation. The review will determine whether this issue represents a performance deficiency. This issue is identified as URI 05000261/2011003-1, Rainstorm Results in Flooding of the Power Block. |
| 05000261/FIN-2011004-01 | 2011Q3 | Robinson | Water Intrusion into Safety-Related Buildings due to Inadequate Design of Site Storm Water Runoff Drainage System | A self-revealing apparent violation (AV) of 10 CFR 50, Appendix B, Criterion III, Design Control, was identified for the licenseei12s failure to consider how the aggregate changes to the sitei12s topography could impact the sitei12s ability to drain storm water runoff and adequately respond to localized flooding during periods of heavy rain. This resulted in the ponding of storm water runoff, the subsequent direction of runoff flow towards the power block, overfilling of the retention basin, backup of the storm drainage system, and ultimately, uncontrolled water intrusion into safety-related equipment rooms in the auxiliary building. The licensee took immediate actions to remove the water from the affected plant buildings and grounds. In addition, within a few weeks of the event, the licensee repaired the washed out area of the berm just to the north of the power block, and performed interim adjustments to site topography to limit ponding near the berm. The licensee plans to perform additional site grade and trench restoration and remediation to permanently prevent site ponding. This issue was entered into the licensee\\\'s corrective action program as NCR 468235. The licensee\\\'s failure to consider how the aggregate changes to the site\\\'s topography could impact the site\\\'s ability to drain storm water runoff and adequately respond to localized flooding during periods of heavy rain as required by procedure EGR-NGGC- 0005, Engineering Change, was a performance deficiency. This performance deficiency was considered more than minor because it was associated with the Initiating Events Cornerstone attributes of the Design Control (plant modifications) and Protection Against External Factors (flood hazard), and adversely affected the cornerstone objective to limit the likelihood of those events that upset plant stability and challenge critical safety functions during shutdown as well as power operations. Specifically, the failure to consider aggregate changes to the site\\\'s topography on the site\\\'s ability to drain storm water runoff resulted in uncontrolled water intrusion into safety-related equipment rooms. The inspectors assessed the finding using Inspection Manual Chapter (IMC) 0609, Significance Determination Process (SDP), Att. 4, Phase 1 - Initial Screening and Characterization of Findings, and determined the finding was potentially greater than very low safety significance because the finding increases the likelihood of an external flooding event. As a result, the characterization worksheet for Initiating Events required a Phase 3 analysis using the Individual Plant Examination for External Event Submittal (IPEEE) or other existing plant specific analyses as inputs. The significance of this finding is designated as To Be Determined (TBD) until the safety characterization has been completed by the NRC Senior Reactor Analyst (SRA). The inspectors determined that the cause of this finding was related to the trending and assessment aspect in the Corrective Action Program component of the Problem Identification and Resolution cross-cutting area. |
| 05000261/FIN-2011004-02 | 2011Q3 | Robinson | Failure to Take Prompt Corrective Actions to Establish Guidance to Monitor and Operate Service Water Strainers Following LOOP | The inspectors identified a Green NCV of Technical Specification (TS) 5.4.1, Administrative Controls, Procedures, for failure to establish procedural guidance to monitor Service Water System (SWS) parameters and operate the SWS strainers following a loss of offsite power (LOOP). Following a LOOP, the operator's ability to recover from a plugged SWS strainer would be impacted due to the loss of the associated control alarm and the lack of procedural guidance to manually operate the SWS strainers. The licensee has revised plant procedures to include additional instructions that will ensure that operators can recover from plugged SWS strainers and preserve the operation of the SWS following a LOOP. This issue was entered into the licensee's corrective action program as NCR 473900. The failure to establish procedural guidance to locally monitor SWS parameters and manually operate the SWS strainers following a LOOP was a performance deficiency. This issue was more than minor because if left uncorrected this finding would have the potential to lead to a more significant safety concern. Specifically, the inability to clean the service water strainers, following a prolonged LOOP, could impact the operation of the service water system. The SDP Phase 1 screening determined that this finding was within the mitigating systems cornerstone and was potentially risk significant due to a seismic, flooding or severe weather initiating event and therefore required a Phase 3 SDP analysis. An NRC Senior Reactor Analyst (SRA) determined the lack of procedure for a loss of the service water strainers due to an external event (i.e., loss of offsite power removing power to the strainers and causing debris to clog the system) was of very low risk significance i.e., Green. The main contributors to the low risk results were: 1) the low likelihood of a total loss of service water event, and 2) the probability of recovery of the strainers and/or the system despite the lack of procedures. The inspectors determined that the finding has a cross-cutting aspect in the Corrective Action Program component of the Problem Identification and Resolution area, because the licensee failed to thoroughly evaluate the issue such that the resolution addressed the cause and extent of conditions, as necessary. Specifically, licensee's evaluation of the NCR associated with the lack of plant procedures to manually operate the SWS, failed to recognize that the control room indication associated with a plugged SWS strainer would be lost following a LOOP. |
| 05000266/FIN-2015003-01 | 2015Q3 | Point Beach | Incomplete Functionality Assessment for Flooding in the Diesel Generator Building | The inspectors identified a finding of very low safety significance for the licensees failure to follow procedure EN-AA-203-1001, Operability Determinations/Functionality Assessments, Revision 19. Specifically, when the licensee identified that internal flood sources in the diesel generator building (DGB) were larger than the drain capacity, they failed to identify all affected structures, systems, and components (SSCs). The DGB contains predominately Train B emergency power systems; however, the fuel oil transfer pumps for the Train A emergency diesel generators are located in the southeast corner of the building. The licensee failed to assess the effects of flooding on the Train A fuel oil transfer pumps. The licensees corrective actions included the creation of an adverse condition monitoring plan, which implemented an hourly flood watch in the DGB when the fire pump was manually started. The inspectors determined that the finding was more than minor, because if left uncorrected, it would potentially result in a more safety significant issue. Specifically, the failure to evaluate the effects of flooding on all SSCs resulted in inadequate compensatory measures. The inspectors determined the finding could be evaluated using the significance determination process (SDP) in accordance with IMC 0609, Significance Determination Process, Attachment 0609.04, Initial Characterization of Findings, dated June 19, 2012, and Appendix A, The Significance Determination Process for Findings At-Power, Exhibit 2, Mitigating Systems Screening Questions, dated June 19, 2012. For the time period in question, May 17, 2015 to September 17, 2015, the inspectors reviewed the security door card reader reports and starting sump levels for the DGB and found that during times when the fire pumps were running, station personnel had toured the DGB at a frequency that would have identified flooding conditions before a loss of system function. The inspectors concluded that the finding was of very low safety significance (Green), because the inspectors answered No to the Mitigating Systems screening questions. This finding has a cross-cutting aspect of Evaluation (P.2), in the area of Problem Identification and Resolution (PI&R), for failing to thoroughly evaluate issues to ensure that resolutions address causes and extent of conditions commensurate with their safety significance. |