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| Start date | Title | Description | Topic | |
|---|---|---|---|---|
| ENS 55715 | 27 January 2022 16:38:00 | Loss of Meteorlogical Data Acquisition System | The Licensee provided the following information via email: On January 27, 2022 at 1038 CST, with Cooper Nuclear Station in Mode 1, 100 percent power, the meteorological tower primary and backup data acquisition system failed, which resulted in a loss of meteorological data to the plant. Information technology personnel investigated and restored the primary system to service. Meteorological data to the plant was restored at 1105 CST on January 27, 2022. This notification Is being made due to a loss of emergency assessment capability In accordance with 10 CFR 50.72(b)(3)(xiii). The NRC Resident Inspector has been Informed.
The following information was provided by the licensee via fax: This notification is being made to retract event EN 55715 that was reported on January 27, 2022. Based on further investigation, the Emergency Plan and Emergency Plan Implementing Procedures provide acceptable alternative methods for performing emergency assessments that are in addition to the data obtained from the primary and backup meteorological tower information. It was determined that no actual or potential major loss of emergency assessment capability existed per 10 CFR 50.72(b)(3)(xiii). This is consistent with NUREG 1022, Revision 3, Supplement 1 and NEI 13-01, Revision 0. The NRC Resident Inspector has been notified of the retraction. Notified R4DO (O'Keefe) | |
| ENS 54049 | 5 May 2019 19:05:00 | En Revision Imported Date 5/31/2019 | EN Revision Text: SECONDARY CONTAINMENT DECLARED INOPERABLE DUE TO POTENTIAL EQUIPMENT FAILURE At 1405 CDT, Secondary Containment differential pressure exceeded the Technical Specification limit due to a potential equipment failure. This required entry into (Limiting Condition of Operation) LCO 3.6.4.1 Condition A for Secondary Containment inoperability. An event or condition that could have prevented the fulfillment of a safety function requires an 8 hour report per 10 CFR 50.72(b)(3)(v)(C) for Control of Rad Release. Secondary Containment differential pressure was restored to greater than or equal to 0.25 inches vacuum, water gauge in accordance with plant procedures. Secondary Containment was declared operable at 1600 CDT. The issue has been entered in the Corrective Action Program and investigation of the cause is in progress. The NRC Senior Resident Inspector has been informed of this condition.
CNS (Cooper Nuclear Station) is retracting the 8-hour notification made for event 54049 which occurred on May 5, 2019 at 1405 CDT. Subsequent evaluation determined that no equipment failure occurred. In addition, there were no procedure inadequacies or human performance issues identified. The indications observed were expected and part of a pre-planned evolution which included entry into a planned LCO for the Secondary Containment. The NRC Resident Inspector has been notified. Notified the R4DO (Kozal). | |
| ENS 53646 | 5 October 2018 05:00:00 | En Revision Imported Date 10/25/2018 | EN Revision Text: MAIN STEAM ISOLATION VALVES EXCEEDED PRIMARY CONTAINMENT LOCAL LEAK RATE ACCEPTANCE CRITERIA At 0520 (CDT), on October 05, 2018, it was discovered that a Primary Containment local leak rate test performed on Main Steam Isolation Valves (MSIV) exceeded its acceptance criteria. During Mode 1, 2, and 3, Surveillance Requirement 3.6.1.3.10 requires MSIV leakage for a single MSIV line to be less than or equal to 106 standard cubic feet per hour (scfh) when tested at 29 psig and Surveillance Requirement 3.6.1.3.12 requires the combined leakage rate for all MSIV leakage paths to be less than or equal to 212 scfh when tested at 29 psig. As-found for the 'C' MSIV line leakage results were unquantifiable and gave a (minimum) path value greeter than 160 scfh. This leakage rate lead to Surveillance Requirement 3.6.1.3.10 and 3.6.1.3.12 limits to be exceeded. This event is being reported as a condition of the nuclear power plant, including its principal safety barriers, being seriously degraded per 10 CFR 50.72(b)(3)(ii)(A) since the Primary Containment Isolation Valves leakage limits for MSIVs were exceeded. The NRC Resident Inspector has been notified.
CNS (Cooper Nuclear Station) is retracting the 8-hour non-emergency notification made on October 5, 2018 at 0520 CDT (EN# 53646). Subsequent evaluation concluded that overall as-found 'C' MSIV leakage rate was not at a level that exceeded the surveillance requirement 3.6.1.3.10 and 3.6.1.3.12 limits and thus the Primary Containment Isolation Valve leakage rate limits for the MSIVs were not exceeded. The NRC Senior Resident Inspector has been notified. Notified the R4DO (Drake). | |
| ENS 53476 | 26 June 2018 05:00:00 | En Revision Imported Date 8/14/2018 | EN Revision Text: CONTROL ROOM EMERGENCY FILTRATION SYSTEM DECLARED INOPERABLE On June 26, 2018, at 1630 CDT, the Control Room Emergency Filtration System (CREFS) was declared inoperable when Main Control Room Supply Fan SF-C-1B was discovered to have elevated vibrations that brought into question the ability to meet its mission time. CREFS is a single train safety system. Per 10 CFR 50.72(b)(3)(v)(D), an 8 hour report is required due to the fact that at the time of discovery this condition could have prevented the fulfillment of a safety function of an SSC (System Structure or Component) that is required to mitigate the consequences of an accident. The licensee has notified the NRC Senior Resident Inspector.
The following retraction was received from Cooper Nuclear Station (CNS) via facsimile and phone call: CNS is retracting the 8-hour non-emergency notification made on June 26, 2018 at 1630 CDT (EN# 53476). Subsequent evaluation concluded that overall vibration levels were not at a level that would impact the ability of the Main Control Room Supply Fan SF-C-18 to perform its safety function for its required mission time and the CREFS therefore, was operable. The NRC Senior Resident Inspector has been notified. Notified the R4DO (Deese). | Time of Discovery Mission time |
| ENS 53128 | 19 December 2017 19:40:00 | Diesel Generators (Dgs) Declared Inoperable Due to a Common Issue | During regular power operations at 100% power, DG#1 and DG#2 were declared inoperable due to a common issue associated with indicating lights and the associated sockets installed in various control and auxiliary circuits for both DG's. The indicating lights in question are incandescent 120V AC style 120MB bulbs in a socket with a 550 ohm resistor. Style 120MB light bulbs have a failure mechanism where the bulb can cause a short circuit rather than the more common open circuit that is expected when an incandescent bulb filament fails. Cooper originally believed that the socket's integral resistor was sufficient to protect the circuit. In testing performed by an outside laboratory and confirmed on-site using warehouse stock, it was determined that the integral resistor may not have the power dissipation capability to protect the circuit ln which the light and socket are installed if a bulb fails in short circuit. This condition resulted in both DG's being declared inoperable at 1340 (CST) due to a loss of reasonable expectation that they would meet their safety function required action to start, load and run to support loads required to mitigate the consequences of an accident. This is a loss of safety function under 10CFR 50.72(b)(3)(v)(D) subject to an 8 hour report. As a result of both DG's being inoperable, the Control Room Emergency Filtration System is also inoperable. This is also a loss of safety function subject to an 8 hour report for the same criterion. The Senior Resident has been notified.
CNS is retracting the 8-hour non-emergency notification made on December 19, 2017 at 1340 CST (EN# 53128). Subsequent evaluation concluded a postulated lamp short circuit failure in any of the affected circuits would not impact the ability of the Diesel Generators to perform their safety function and therefore, were operable. With DG operability not affected, the Control Room Emergency Filtration System also remained operable. The NRC Resident Inspector has been notified. Notified the R4DO (Werner). | |
| ENS 53022 | 18 October 2017 07:09:00 | Hpci Declared Inoperable | Eight hour report due to HPCl (High Pressure Coolant Injection) inoperability. HPCl valve operability testing was performed on October 18, 2017. Following satisfactory completion of opening stroke timing, the control switch for HPCI-MOV-MO19, HPCI Injection Valve, was taken to close. The valve indicates that it moved to an intermediate position, but it has not indicated that it has fully closed. This resulted in the valve being declared inoperable. This valve is normally closed and automatically opens on a HPCI initiation signal. HPCl was previously declared inoperable at time 0136 (CDT) on October 18 for surveillance testing. Entry was made into Tech Spec LCO 3.5.1 Condition C - HPCI System Inoperable at that time. Required Actions for Condition C are to verify by administrative means RCIC System is operable within 1 hour and restore HPCI System to operable status within 14 days. RClC was verified operable by administrative means concurrent with declaration of HPCI inoperable. Troubleshooting activities for HPCI are being planned. HPCI is a single train safety system. This report is submitted as a condition that at time of discovery could prevent the fulfillment of the safety function of an SSC (structures, systems, and components) needed to mitigate the consequences of an accident. This condition has been entered into the CNS Corrective Action Program. The licensee notified the NRC Resident Inspector.
CNS is retracting the 8-hour non-emergency notification made on October 18, 2017 at 0209 CDT (EN# 53022). Subsequent evaluation concluded HPCI-MOV-MO19 was still capable of performing its safety function with the failed torque switch identified during troubleshooting and would have supported the operability of the HPCI system. HPCI-MOV-MO19 only has a safety function to open to support HPCI safety function. The failed torque switch only affects the close function of the valve; therefore the HPCI system remained fully capable of performing its required safety function and was operable with the identified condition. The NRC Resident Inspector has been notified. Notified R4DO (Haire). | Time of Discovery |
| ENS 51240 | 18 July 2015 17:14:00 | Standby Gas Treatment System Declared Inoperable Due to Inoperable Sump Pumps | At 1214 CDT on 7/18/2015, during normal surveillance testing of Z sump, Z2 sump pump run time was found to exceed its upper Augmented IST limit, rendering it non-functional. Operators continued with the surveillance, opening the power supply breaker to Z1 sump pump, rendering it non-functional also. When this was identified, station personnel backed out of testing and restored power to Z1 sump pump. Z sump functions to limit condensation buildup in the common Standby Gas Treatment System (SGT) discharge line to support SGT operability. One sump pump is required to be functional to support SGT operability. With both Z sump pumps non-functional, operability of both trains of SGT is not assured. Loss of both trains of SGT constitutes a loss of safety function for control of rad release and accident mitigation per 10 CFR 50.72(b)(3)(v) functions (C) and (D). The breaker for Z1 sump pump was reclosed at 1225 CDT, restoring functionality to Z1 sump pump and operability to both trains of SGT. Both Z sump pumps were considered non-functional and unable to support SGT operability for a period of 11 minutes. The licensee notified the NRC Resident Inspector.
Cooper Nuclear Station (CNS) is retracting the 8-hour non-emergency notification made on July 18, 2015 at 1839 EDT (EN# 51240). The notification on July 18, 2015 reported a condition where the two Z Sump Pumps were considered non-functional and unable to support the operability of the Standby Gas Treatment System (SGT). Subsequent evaluation concluded that Z2 Sump Pump was functional with the run time identified and would have supported the operability of SGT during the time the Z1 Sump Pump breaker was open for surveillance testing. A loss of safety function did not exist. A modification had been previously installed at CNS that prevents the buildup of significant amounts of water in a hold-up line. This volume of water was the basis for the original Z Sump Pump IST (in-service-testing) run times. With the buildup of water previously resolved, the calculated Z Sump Pump IST run times are much longer than measured on July 18, 2015. Notified the R4DO (Hagar). | |
| ENS 50854 | 27 February 2015 23:56:00 | Unanalyzed Condition Concerning Control Room Habitability Analysis | Cooper Nuclear Station became aware of the installation of two 12,000 gallon anhydrous ammonia tanks approximately 1.5 miles from the site. This amount of anhydrous ammonia at that distance exceeds the control room habitability hazardous chemical analysis previously evaluated for the nuclear station. The control room staff has been informed of the condition and have reviewed the appropriate abnormal procedures for actions to take in the case of a leak. This potentially represents an unanalyzed condition that significantly degrades plant safety and is reportable under 10 CFR 50.72(b)(3)(ii)(B). The licensee has notified the NRC Resident Inspector.
Subsequently it was determined that the Control Room Habitability Analysis that was performed in response to the NRC's post-TMI requirements bounds the identified condition. This analysis includes the potential of a toxic chemical leak from a 725-ton tank on a river barge carrying anhydrous ammonia. The volume of chemical, and distance from the control room, included in the post-TMI habitability analysis bounds the conditions found with the newly constructed anhydrous ammonia tanks. The licensee notified the NRC Resident Inspector. Notified the R4DO (Farnholtz). | Unanalyzed Condition |
| ENS 49308 | 27 August 2013 04:05:00 | Post Accident Monitoring Instrumentation Power Supplies Potentially Degraded | At 2305 on 26AUG13 the Shift Manager Declared PC-ES-1A and PC-ES-1B inoperable due to a Part 21 Notification that called the operability of the equipment into question. PAM (Post Accident Monitoring) Instrumentation LCO 3.3.3.1.A and 3.3.3.1.C were entered for Functions 1 (Reactor Pressure), 3 (Containment Level), and 7 (Containment Pressure). Both divisions are potentially affected. LCO 3.3.3.1.C represents a 7 Day shutdown LCO. CR-CNS-2013-6096 identified a Part 21 issue associated with Foxboro Power Supply PC-ES-1A and PC-ES-1B. The Part 21 issue identifies a potential failure mechanism in which the adhesive backing on aluminum tie-wrap base used in the power supply fails and the base becomes detached from the power supply case. The nylon tie-wrap affixed to these bases becomes brittle with age and fails releasing the aluminum base to fall into the power supply where it has the potential to short out electrical equipment and fail the power supply. The equipment affected is: PC-LRPR-1A, PC-LRPR-1B, NBI-PR-2A, and NBI-PR-2B. These power supplies affect both Control Room Reg. Guide 1.97 Cat A instruments and associated PMIS/SPDS points. This instrumentation is utilized for emergency plan actions (EALs) and EOP 3A actions in addition to monitoring the previously mentioned functions. The loss of this instrumentation represents a significant loss of emergency response capability. The affected instruments are for indication only and perform no active safety functions. All of the referenced instrumentation is currently functioning as required. This condition has been entered into the CNS Corrective Action Program. A 60 day Licensee Event Report is not required for this event. The licensee notified the NRC Resident Inspector.
This notification is being made to retract Event Notification EN 49308 that was reported on August 26, 2013. This EN identified Cooper Nuclear Station had equipment potentially affected by a Part 21 issue in which a potential failure mechanism of adhesive on aluminum ty-wrap bases used in two power supplies fails and the base becomes detached from the power supply case. The nylon ty-wraps affixed to these bases become brittle with age and fails, releasing the aluminum base to fall into the power supply with the potential to short out electrical equipment. These power supplies affected Post Accident Monitoring equipment that is used to monitor for Emergency Plan Actions (EALs) and EOP 3A actions. This equipment provides no active safety function and is used for indication only. The equipment affected included PC-ES-1A and PC-ES-1B and they provided divisional power to Post Accident Monitoring equipment for Reactor Pressure, Containment Level and Containment Pressure. Ten of the eleven aluminum cable tie holders were found to still be in place during the inspection of PC-ES-1A under WO 4972878. The one cable tie holder that was found to not be adhered was initially attached when the power supply was opened. Based on physical inspection of the removed cable ties and the installed wiring, and ten of the eleven cable tie holders being adhered upon inspection of the power supply it is concluded that this power supply remained qualified to perform its function under all design conditions in its as found configuration. The failure mechanism identified in the Part 21 required two failures. The inspection performed on PC-ES-1A only revealed the failure of one cable tie mount and not the widespread failures reported in the Part 21. Additionally, the cable ties removed from PC-ES-1A remained flexible and would not have failed during a seismic event based on engineering judgment. As such, PC-ES-1A remained capable of performing its design function. By engineering judgment PC-ES-1B also remained capable of performing its function. Therefore, there was no actual or potential major loss of emergency assessment capability per 10 CFR 50.72(b)(3)(xiii). The licensee notified the NRC Resident Inspector. Notified the R4DO (Gaddy). | Post Accident Monitoring |
| ENS 48865 | 13 March 2013 22:26:00 | Loss of Reasonable Assurance of Operability for Standby Liquid Control Tank | Information Notice IN 2012-01 on seismic qualification of Standby Liquid Control (SLC) tanks was evaluated in 2012 to assess immediate operability of the SLC system based on SLC Test Tank and Mixing Tank not being qualified to Seismic Class 1S. Based on calculation NEDC 12-015 in response to IN 2012-01, (Cooper Nuclear Station) CNS concluded that SLC was still operable with the test tank full. Long-term actions from the 2012 condition were completed by issuance of calculation NEDC 13-010 and evaluation EE 13-009. NEDC 13-010 concludes that the SLC storage tank is qualified when full and the test tank and mixing tank are qualified when empty. No procedure step existed in the SLC surveillances to ensure the test tank is drained prior to restoration of SLC to an operable status to ensure it remained fully qualified to its NEDC 13-010 design. Further, no Caution Order or Standing Order existed to ensure short-term control until a procedure change could be implemented. So, as a short-term action, CNS implemented a Standing Order to establish positive control of the test tank. The Standing Order directs that SLC be declared INOPERABLE if the Test Tank is filled. Initially, this was thought to be a conservative measure only, because CNS judged that reasonable assurance of OPERABILITY remained due to conservative assumptions in NEDC 13-010. However, on 3/19/13 at 2146 CDT, the Prompt Operability Determination was changed to credit the Standing Order as a compensatory measure needed to maintain or enhance OPERABILITY of SLC. Therefore, CNS had lost reasonable assurance of OPERABILITY as of 03/13/2013 at 1726 CDT when the Control Room was notified that NEDC 13-010 concluded the test tank and mixing tank had to be empty to preserve the required seismic qualification, and an 8-hour report should have been made prior to 0126 CDT on 03/14/2013. Currently the SLC Test Tank is drained and SLC is OPERABLE. The licensee has notified the NRC Resident Inspector.
This notification is being made to retract Event Notification EN #48865 which was reported on March 28, 2013 for an event occurring on March 13, 2013. This EN identified Cooper Nuclear Station had lost reasonable assurance of OPERABILITY of the Standby Liquid Control (SLC) system based on a CNS design calculation which supported that the SLC test tank was not seismically qualified when full of water. Subsequently, this calculation was re-evaluated specifically in support of determining OPERABILITY. This re-evaluation determined the SLC system remained OPERABLE when the consideration of nozzle loads is removed. The ability of Class IIS (ASME American Society Mechanical Engineering) seismic components to meet Class II/I (ASME) does not require the consideration of nozzle loads. The SLC test tank, which is a Class IIS (ASME) component, does not fail when filled if no nozzle loads are considered. As such, there was no loss of safety function for SLC. The licensee will notify the NRC Resident Inspector. Notified R4DO (Drake). | |
| ENS 48429 | 22 October 2012 05:10:00 | Potential Condition Could Bypass Flooding Barriers and Affect Residual Heat Removal Equipment | During a walkdown evaluating potential for adverse consequences of site flooding, per 10CFR50.54(f) request, a condition was identified which had the potential to adversely impact the ability to address external flooding conditions. The old Emergency Offsite Facility (which currently houses information technology offices) has a drain pipe which connects to Sump AA in the Augmented Radwaste (ARW) building and bypasses the flooding barriers erected per maintenance procedure 7.0.11 in the event of site flooding. Per the USAR, the basis for site flooding is a flood with concurrent surge effects on exposed safety related structures reaching an elevation of 905 feet. This elevation is 2.0 feet above the grade elevation of 903 feet. Flooding protection for important site facilities is provided by installing temporary barriers protecting to elevation 906 feet. Primary and Secondary Flood Barriers are installed at the ARW building external entrances on the 903 feet elevation to protect the Reactor Building from external flood water. The drain piping from the old EOF floor drain and shower is piped directly to Sump AA in the ARW building basement. This is a 3 inch pipe which drains by gravity. There are no isolation features on the pipe, and no barriers to flooding are provided for this facility, thus the potential exists to bypass the flood barriers which would be erected around the ARW Building. Flooding of the building basement could result, disabling processing equipment. If the basement fills up, flood waters could enter the Reactor Building through the internal entrance, which has no additional protection installed. Floodwaters could then affect equipment which is required to remove residual heat. This condition has been determined to be reportable per 50.72(b)(3)(v) - Any event or condition that at the time of discovery could have prevented the fulfillment of the safety function of SSCs that are needed to remove residual heat. The potential condition was identified on 10/20/2012. Evaluation of the condition and the potential impact was completed and reportability determined on 10/22/2012. The condition has been entered into the Corrective Action Program. The licensee notified the NRC Resident Inspector.
During a walk down evaluating the potential for adverse consequences of site flooding per 10CFR50.54(f) request, a condition was identified which had the potential to adversely impact the ability to address external flooding conditions. The Optimum Water Chemistry (OWC) building has 5 floor drains, at ground level elevation 903 ft, which connect to a common 3 inch drain pipe which connects to a sanitary sump located in the Turbine building, at an elevation of 882 ft, and bypasses all flooding barriers erected per maintenance procedure 7.0.11 in the event of site flooding. Per the USAR, the basis for site flooding is a flood with a concurrent surge effect on exposed safely related structures reaching an elevation of 905 ft. This elevation is 2 ft above the grade of the floor drains. Flooding protection for important site facilities is provided by installing temporary barriers which provide protection to an elevation of 906 ft. Primary and secondary barriers are installed at the Turbine building external entrances to protect the Reactor building from external flood waters. Additional secondary barriers are erected inside the Turbine building to provide additional protection to the Diesel Generator rooms. The drain piping from the OWC building floor drains is piped directly to the sanitary sump located in the Turbine building. There are no isolation features on the piping and no barriers to flooding are erected between the Turbine building and Reactor building thus the potential exists to bypass the flood barriers erected around the Turbine building. Flooding of the Turbine building could result in the accumulation of water in sufficient quantities to fill the Turbine building 882.5ft elevation to the height of the external floodwaters which would then be allowed to flow unimpeded by flooding barriers to the Reactor building through the internal entrance which has no additional barriers installed. These floodwaters could then affect equipment, located within the Reactor building, which is required to remove residual heat. This condition has been determined to be reportable per 50.72(b)(3)(v) - Any event or condition that at the time of discovery could have prevented the fulfillment of the safety function of SSC's. that needed to remove residual heat. This condition was identified at 1550 (CDT on) 10/22/2012 and has been entered into the Corrective Action Program. The licensee informed the NRC Resident Inspector. Notified R4DO (Hagar).
This notification is being made to retract Event Notification EN #48429 which reported a loss of safety function due to the discovery of two flow paths (one from the old Emergency Operating Facility and one from the Optimum Water Chemistry building) where an external event flood event at 905 feet would result in flooding of the Turbine and Radwaste basement and eventually the Reactor building basement. Upon further review, the design basis Probable Maximum Flood for CNS is 903 feet. The two water entry points discussed in the Event Notification are above the 903 foot elevation. Wave energy would be dissipated before reaching any of the main buildings so there would be a minimal influx of water into the structures. As such, there is no loss of safety function for equipment in the Reactor building basement. NPPD therefore retracts Event Notification EN #48429. The NRC Resident Inspector has been notified. Notified R4DO (Farnholtz). | Time of Discovery |
| ENS 48237 | 27 August 2012 17:00:00 | Both Emergency Diesel Generators Declared Inoperable | At 12:00 CDT maintenance personnel identified a pinhole leak from the Division 1 Service Water System piping in the Service Water Pump Room. Division 1 Service Water (SW) was declared inoperable and LCO 3.7.2 Condition A was entered due to a potential loss of structural integrity. This directs entry into LCO 3.8.1 for Diesel Generator #1 made inoperable by SW. DG 2 was previously made inoperable at 05:39 CDT on 8/25/2012 due to an unrelated issue regarding rain water inleakage into the DG 2 Room. Control Room Emergency Filtration system (CREFs) is aligned to Div 1 power. LCO 3.7.4 Condition A is applicable, requiring restoration of CREFs to operable status within 7 days. TRM LCO 3.6.1 condition A and B also apply, requiring (A) Restoration of containment spray subsystem A to OPERABLE status within 7 days and (B) Restore one RHR containment spray subsystem to operable status within 8 hours. DG 1 and DG 2 comprise the onsite emergency power systems. Both DGs inoperable is reportable per 10CFR50.72(b)(3)(v)(D) as a condition that could prevent fulfillment of the safety function of structures or systems needed to mitigate the consequences of an accident. Actions were taken to expedite repairs of the DG 2 roof leak and to further characterize the Division 1 SW piping leak. LCO 3.8.1 Condition E allows 2 hours to restore one DG to operable status or enter Condition F, to be in Mode 3 in 12 hours, which was entered at 14:00. Repairs to the roof leak on the DG 2 room were completed, after which DG 2 was declared Operable at 18:30. LCO 3.8.1 Conditions E and F required shutdown were exited at this time. LCO 3.8.1 Condition B for DG 1, and 3.7.2 for SW Loop A, continue to be active. Planning to repair the SW piping pinhole leak is continuing. There were no adverse grid conditions during the period both DGs were inoperable. The NRC Resident has been informed of the condition. No media or press release is planned at this time.
This notification is being made to retract Event Notification EN #48237 which reported a loss of safety function due to both onsite Emergency Diesel Generators (DGs) being simultaneously INOPERABLE. On 8/25/12 at 0539 CDT, DG#2 was declared INOPERABLE due to rain water in-leakage into the DG#2 room. Condition B of LCO 3.8.1 was entered. and Required Actions were being taken to restore the INOPERABLE DG within 7 days. Subsequently, on 8/27/12 at 1200 CDT Maintenance personnel identified a pinhole leak from the Division I Service Water System piping in the Service Water Pump Room. Division I Service Water was declared INOPERABLE and LCO 3.7.2 Condition A was entered due to a potential loss of structural integrity. This prompted entry into LCO 3.8.1 Conditions E and F which require shutdown, because DG#1 was made INOPERABLE by SW. Both DG's INOPERABLE is reportable per 10CFR50.72.b.3.v.D as a condition that could prevent fulfillment of a safety function of structures or systems needed to mitigate the consequences of an accident. Repairs to the roof leak on the DG#2 room were completed, after which DG#2 was declared Operable at 1830 CDT on 8/27/2012. LCO 3.8.1 Conditions E and F were exited at the time. LCO 3.8.1 Condition B for DG#1, and 3.7.2 for SW Loop A, continued to be active, and planning to repair the pin-hole leak continued. Subsequent investigation and UT examinations provided data which enabled SW Division 1 and DG#1 to be declared OPERABLE on 8/30/2012 at 0528 CDT. An evaluation of this condition concluded that further characterization of the SW Piping Pin-Hole leak enabled ASME Code Case N-513-3 to be applied to determine piping structural integrity was maintained. SW ability to supply required flows to its loads is not adversely diminished, because the flaw is small. Water leaking from the flaw will not adversely affect any other equipment important to safety by spray or flooding. The piping is compliant with ASME code. Based on this evaluation, the Division 1 SW system can perform its safety function and is OPERABLE. With Division 1 SW subsystem capable of fulfilling its safety function, DG#1 was therefore also capable of fulfilling its safety function during the period of SW subsystem INOPERABILITY. Consequently, during the period of DG#2 INOPERABILITY, DG#1 was capable of fulfilling the safety function of the onsite emergency power system. NPPD therefore retracts Event Notification EN 48237. The NRC Resident has been informed of this retraction. Notified R4DO (Azua). | |
| ENS 47195 | 23 August 2011 20:30:00 | Crefs Was Declared Inoperable | This telephone report is being made in accordance with 10 CFR 50.72(b)(3)(v) as a loss of safety function for a single train safety system. On August 23, 2011 at 1530 CDT, the clevis pin that connects the valve with the air operator was found not fully inserted on the Control Room HVAC Emergency Bypass System Inlet Valve, HV-AO-271 AV. This valve is normally closed and opens in response to a Group 6 isolation signal to align the Control Room Emergency Filtration System) (CREFS) to outside air. A retaining clip at one end of the pin was found to be missing, allowing the pin to partially back out of the clevis. The pin was found engaged with half of the clevis. This condition resulted in declaring CREFS inoperable at 15:30 CDT, and CNS entered LCO 3.7.4 Condition A which requires the CREF system to be restored to OPERABLE status in 7 days. The cause of the displaced clevis pin is under investigation. The licensee has notified the NRC Resident Inspector.
This notification is being made to retract Event Notification EN# 47195 which reported a loss of safety function for a single train safety system due to the unplanned inoperability of the Control Room Emergency Filtration System (CREFS). CREFS was declared inoperable on August 23, 2011 per LCO 3.7.4 due to finding a clevis pin not fully inserted on the valve operator for the Control Room HVAC Emergency Bypass System Inlet Valve IIV-AOV-271AV. This normally closed valve opens on a Primary Containment Group 6 Isolation signal to align CREFS to outside air. The retaining clip at one end of the pin was found missing which allowed the pin to partially back out of the clevis. Cooper Nuclear Station (CNS) recently completed its trouble shooting of the as-found condition of the pin and a subsequent evaluation of its ability to withstand seismic loading. CNS determined that CREFS would have been able to fulfill its safety function. The clevis pin was shown via testing to remain engaged when the valve was stroked. The seismic evaluation showed that the maximum seismic force is less than one-tenth of the estimated force required to remove the pin, and consequently it is not credible that the pin would have become disengaged in a seismic event. CREFS did not lose the ability to perform its safety function. The NRC Resident Inspector has been notified. Notified the R4DO (Walker). | |
| ENS 44671 | 20 November 2008 18:30:00 | Control Room Emergency Filtration System Inoperable | On 20 Nov 08 at 1230, the Control Room Emergency Filtration System (CREFS) was declared inoperable due to a report that a non-running Control Room supply fan discharge damper was found partially open. Per the System Operating Procedure, the idle fan's discharge damper must be fully closed to assure operability. With the damper not closed, reasonable assurance that CREFS would fulfill its safety function could not be established. With the Idle Control Room supply fan discharge damper not in the closed position, some portion of the air discharged from the operating Control Room supply fan will go backwards through the idle supply fan to the suction side of both supply fans. The CREFS fan discharges to the Control Room supply fan suctions. With CREFS in this as-found line-up, there is no assurance that the flow through CREFS is high enough to meet the design requirements assumed in control room occupant dose calculations. The Control Room supply fans and discharge dampers are required support features for CREFS at CNS. This is a single train system and per 10CFR50.72(b)(3)(v)(D) an 8 hour report is required due to the fact that at the time of discovery this condition could have prevented the fulfillment of the safety function of an SSC that is required to mitigate the consequences of an accident. The licensee notified the NRC Resident Inspector. The damper was returned to a fully closed position at the time of discovery, and CREFS was returned to operable status.
This notification is being made to retract Event Notification EN# 44671 which reported a loss of safety function due to the unplanned inoperability of the Control Room Emergency Filtration (CREF) system. The CREF system was declared inoperable due to the non-running control room supply fan discharge damper found partially open on November 20, 2008. Cooper Nuclear Station has determined through further evaluation that while the CREF system was procedurally required to be declared inoperable, the ability of the CREF system to perform its safety function was not lost. Testing was performed on December 19, 2008, with the non-running control room supply fan discharge damper aligned in the as-found condition (~25% open) of November 20, 2008 and again tested with the damper aligned to 50% open. Technical Specifications surveillance flow requirements were met in both tests. Using the results of the test and inspection of the discharge damper it has been concluded that during the ten days the damper was out of position, the CREF system was still capable of performing its safety function and satisfying Technical Specifications requirements. Notified R4DO (Werner). | Time of Discovery |
| ENS 42939 | 27 October 2006 08:37:00 | Containment Pathway Declared Inoperable Following Local Leak Rate Testing | This condition is being reported in accordance with the requirements of 10CFR50.72(b)(3)(ii) as an event or condition that results in: (A) The condition of the nuclear power plant, including its principal safety barriers, being seriously degraded. During local leak rate testing (LLRT) of the 'B' reactor feed line to the reactor, both primary containment boundary check valves (RF-CV-13CV and RF-CV-14CV) failed LLRT. Efforts to quantify the leak rate were unsuccessful. The maximum leakage indicated on the test equipment used is 424 standard cubic feet per hour (SCFH). The allowable leakage (La) for Primary Containment is 317.41 SCFH. The affected primary containment pathway was declared inoperable. CNS is in MODE 5 for refueling with vessel level greater than 21 feet above the flange and the spent fuel pool gates removed. No fuel movements or operations with the potential to drain the reactor vessel were in progress. Primary containment is not required per CNS Technical Specifications in this mode of operation. The NRC Senior Resident Inspector has been notified.
This notification is being made to retract Event Notification #42939 which reported a Primary Containment isolation pathway being declared inoperable following Local Leak Rate Testing (LLRT); specifically, the 'B' reactor feed line containment boundary inboard and outboard check valves. CNS has determined that the LLRT test method established test conditions that were not representative of the conditions under which the check valves would be required to perform their safety function. Inspection, in-situ testing and evaluation demonstrated the reactor feed line check valves would have performed their isolation functions during credible accident conditions. Thus, the condition was not a serious degradation of a principal safety barrier. During the normal plant shutdown to refueling outage RE23 with gradually decreasing feed flow, the check valve discs had not completely settled into the valve seats. Due to the slow pressurization rate of the LLRT working medium (air), sufficient differential pressure across the valve could not be developed which resulted in failing the test. Inspection of the check valves in their as-found condition revealed that a slight contact between the disc and the top of seat left a crescent shaped gap which, at the maximum (the bottom), was no more than 1/2 inch. An in-situ test measured the force needed to settle the disc into the seat and found it equated to a flow related pressure drop of less than 1 psid. A review of accident sequences concluded that post-accident pressurization of the feed lines would have closed the check valves for all credible accident scenarios. Check valve disc to pivot arm spacing adjustments were made to ensure sufficient disc float to reseat and fully close the valve from any open position. Subsequently, LLRT results were satisfactory. The licensee notified the NRC Resident Inspector. R4DO (Johnson) notified. | |
| ENS 41382 | 7 February 2005 21:58:00 | Residual Heat Removal System Inoperable Due to Emergency Diesel Generator Trip During Testing | This report is being made pursuant to 10CFR50.72(b)(3)(v)(B) 'Any event or condition that at the time of discovery could have prevented the fulfillment of the safety function of structures or systems that are needed to: (B) Remove residual heat;' This report is being made due to a trip of the Emergency Diesel Generator during testing that resulted in the RHR loops potentially becoming depressurized. This has the potential to render all RHR Shutdown Cooling unavailable and prevent the removal of decay heat. Sequence of events (all times CST): At 12:00 (02/07/05), Shutdown Cooling was removed from service to prepare for Sequential Load testing of DG #1. This was a planned evolution. At this time decay heat was being removed by the fuel pool cooling system with 2 fuel pool cooling pumps and 2 fuel pool cooling heat exchangers. Time to boil was calculated to be 26 hours. At 15:58, the Sequential Load Test commenced on the inoperable DG. The DG came up to speed and sequenced on the initial loads (RHR pumps, a CS pump and a SW pump). Shortly into the sequencing of the DG, the DG tripped due to a blown fuse in the DG control circuit. Sequential loading was not completed. The trip occurred between 13 seconds and 20 seconds of the sequential load. This resulted in the initial loads losing power. Procedurally, the minimum flow valves for the RHR and CS pumps were being remotely opened from the Control Room at the time the DG tripped. This resulted in low-pressure alarms on both RHR systems and one CS system. One fuel pool cooling pump was deenergized, per design, during the sequential load test. Both fuel pool cooling heat exchangers remained in service. With these conditions, the fuel pool cooling lineup does not qualify as an alternate decay heat removal method. At 16:04, both RHR loops were declared inoperable due to depressurizing the RHR loops. At 16:02, the tripped fuel pool cooling pump was restored to operation and previous decay heat removal was restored. No unexpected rise in temperature occurred during the time that only 1 fuel pool cooling pump was in operation. This reestablished the fuel pool cooling system as an alternate decay heat removal method. At 19:11, the B loop of RHR was returned to a standby lineup and declared operable. At this time investigation into why the DG fuse blew is ongoing. All indications are that other equipment performed as designed. The licensee notified the NRC Resident Inspector.
The following is a correction to the original report received via facsimile (licensee text in quotes): Instead of the minimum flow valves for RHR and CS being opened, the suppression pool inboard cooling valve for RHR and the test line recirculation valve for CS were being opened. The licensee will notify the NRC Resident Inspector. Notified R4 DO (T. Pruett)
The following information was provided by the licensee (licensee text in quotes): On 2/7/2005 at 1558 CST, Cooper Nuclear Station made an 8 hour 50.72 non-emergency notification to the NRC. The report was made pursuant to 10 CFR 50.72(b)(3)(v), 'Any event or condition that at the time of discovery could have prevented the fulfillment of the safety function of structures or systems that are needed to: (B) Remove residual heat.' A control power failure during Emergency Diesel Generator #1 (DG) surveillance testing resulted in the loss of the Residual Heat Removal (RHR) pressure maintenance pump. This resulted in the potential de-pressurization and unavailability of all RHR Shutdown Cooling (SDC) and the ability to remove decay heat using RHR. NUREG 1022 Revision 2 defines the safety functions to be considered for Reportability under this section of the rule as being those that are listed in the regulation itself. Thus, the lost safety function being reported was 'remove decay heat'. Plant conditions prior to the testing were: Mode 5 (Refueling) with the Reactor Vessel and Drywell heads removed and reactor water level flooded up and Spent Fuel Pool transfer gates removed. Division II RHR was in service providing SDC for decay heat removal. In preparation for the DG testing and in accordance with Technical Specifications, all RHR SDC was removed from service. With RHR SDC out of service, reactor coolant circulation was verified to be by natural circulation with operators monitoring reactor coolant temperatures once per hour. Alternate decay heat removal was provided by the credited lineup of two Fuel Pool Cooling (FPC) pumps and two FPC heat exchangers. FPC receives cooling water from the Reactor Equipment Cooling System (REC), which in turn is cooled by the Service Water System (SW). During the preparation period (approximately 4 hours) for the DG #1 testing, reactor coolant temperature was allowed to slowly go from 85 degrees Fahrenheit to 90 degrees Fahrenheit. During load sequencing testing of DG #1, the DG tripped due to a control system failure and de-energized the Division I 4160 Volt (V) critical bus. (Note: The bus was previously de-energized for a short period of time as part of the test.) This caused the pump providing pressure maintenance for the RHR to trip potentially depressurizing the RHR loop (Division II) that had been lined up to provide SDC. A conservative decision was made to declare Division II SDC inoperable during the DG trip recovery. If the test had proceeded as planned one RHR pump would have been running in Division I in the test mode (pumping water to the suppression pool). No RHR pumps would have been running in Division II (lined up to allow the Division I test to be conducted). DG #2 remained in normal standby lineup. Division II 4160 V bus was energized supplying power to connected loads. Due to the DG #1 trip the Division I 4160 V bus was deenergized. Shutdown Cooling using RHR could not be placed in service as a result of the test lineup established for DG #1 testing. Reactor coolant circulation was by natural circulation and reactor decay heat removal was by one FPC pump and two FPC heat exchangers. The trip of one FPC pump is expected and verified during this surveillance test. REC was operating with cooling supplied by Division II SW. During the period of time after the DG trip and prior to the restoration of electrical power to the Division I 4160 V bus, coolant circulation continued by natural circulation with one FPC pump and two FPC heat exchangers providing decay heat removal. At approximately the time of the DG trip coolant temperature was 90 degrees Fahrenheit. Just after power was restored coolant temperature was 89 degrees Fahrenheit. Operators had adjusted REC temperatures and flows to provide additional cooling to Fuel Pool Cooling. An additional FPC pump was started to provide a two FPC pump and two FPC heat exchanger lineup for reactor decay heat removal. The small variation in coolant temperature demonstrates that the FPC lineup was adequate to provide decay heat removal. Engineering performed an evaluation to investigate bulk water temperature response to the event with one FPC pump and two heat exchangers supplying cooling with the fuel pool gates removed. The results show extended periods of time for pool heat-up and are considered bounding. It takes 21 hours for the pool temperature to reach 150 degrees Fahrenheit and 94 hours for the bulk temperature to reach a maximum value of 182 degrees Fahrenheit. Based on this evaluation CNS concludes the maximum bulk temperature would not exceed 182 degrees Fahrenheit. As discussed above, RHR SDC was removed from service to support Emergency Diesel Generator surveillance testing. While RHR SDC was out of service, reactor coolant circulation was provided by natural circulation. At the same time, the safety function of decay heat removal was provided by Fuel Pool Cooling. Since the decay heat removal safety function was never lost this is not a reportable event. The licensee notified the NRC Resident Inspector. Notified the R4DO (Graves).
The following is a change to paragraphs 3 and 4 of the above retraction statement During sequential load testing of DGI, the normal expected response after loads are sequenced on, is to have an RHR pump in each division recirculating back to the suppression pool via the suppression pool cooling line. This path is established when the respective RHR pump automatically starts. During load sequencing testing of DG # 1, the DG tripped due to a control system failure and de-energized the Division I 4160 Volt (V) critical bus. (Note: The bus was previously de-energized for a short period of time as part of the test.). Due to the timing of the DG failure, both RHR pumps started and both suppression pool cooling valves were opened. Subsequently the DG tripped and the RHR pumps stopped due to no power available. The suppression pool cooling valves were unable to be closed prior to depressurizing both RHR loops. A conservative decision was made to declare Division II SDC inoperable during the DG trip recovery. DG #2 remained in normal standby lineup. Division II 4160 V bus was energized supplying power to connected loads. Reactor coolant circulation was by natural circulation and reactor decay heat removal was by one FPC pump and two FPC heat exchangers. The trip of one FPC pump is expected and verified during this surveillance y test. REC was operating with cooling supplied by Division II SW. The NRC Resident Inspector will be informed. Reg 4 RDO(Linda Howell) was notified. | Time of Discovery Time to boil |