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05000389/FIN-2016001-02Saint Lucie2016Q1Failure to Provide Detailed Work Instructions Resulted in a Unit TransientA self-revealing finding was identified for the licensees failure to provide adequate work instructions for the circulating water system 1B1 traveling water screen drive motor replacement. Specifically, the inadequate work instructions resulted in a plant transient in order to remove the associated circulating water pump (CWP) from service. This issue was placed in the licensees corrective action program (CAP) as action request (AR) 2095560. The licensee completed the following corrective actions: (1) Counsel all maintenance supervisors in regard to having a questioning attitude and to seek guidance if unsure; (2) Rewire the 1B1 traveling screen drive motor for the proper rotation; (3) Install labels indicating the proper rotation for all eight traveling screen drive motors; (4) Submit document change requests to update the total equipment database; (5) Update all work orders (WO) for the remaining screen drive starter replacements to provide motor rotation direction and mark the post-maintenance test (PMT) step as a critical step, and; (6) Change clearance requests for traveling screen work to include directions to have electricians on station prior to returning the control switch to automatic. The failure to provide adequate work instructions for replacement of the 1B1 traveling screen motor was a performance deficiency (PD). The PD was more than minor because it was associated with the procedure quality attribute of the initiating events cornerstone and adversely affected the cornerstone objective to limit the likelihood of those events that upset plant stability and challenge critical safety functions during power operations. Specifically, the inadequate WO instructions resulted in installing the 1B1 traveling screen drive motor incorrectly on December 4, 2015. After the maintenance, the system automatically started and the screen rotated backwards. The backward rotation allowed accumulated debris to be transported to the 1B1 debris filter system (DFS) filter and caused it to overload. The resulting high differential pressure (DP) on the DFS filter necessitated the need to lower unit power (plant transient) and required removal of the 1B1 CWP from service. The finding was determined to be of very low safety significance (Green) based on Exhibit 1, Initiating Events Screening Questions, found in IMC 0609, Significance Determination Process, Appendix A, Significance Determination Process (SDP) for Findings At-Power (June 19, 2012). This was due to the fact that the finding did not cause a loss of mitigation equipment relied upon to transition the plant from the onset of the trip to a stable shutdown condition. The inspectors determined the cause of this finding was associated with a cross-cutting aspect of ensuring risks are evaluated and managed before proceeding in the Challenge the Unknown component of the human performance area. Specifically, the licensee did not have a healthy questioning attitude and did not recognize the need to seek guidance when installing a new circulating water system traveling screen motor (H.11).
05000456/FIN-2014003-03Braidwood2014Q2Corrective Actions to Address NCV 05000456/2012005-01; 05000457/2012005-01, "Failure to Maintain Watertight Door Safety Function After Routine Passage"The inspectors identified an unresolved item (URI) associated with the licensees corrective actions to address NCV 05000456/201200501; 05000457/201200501, Failure to Maintain Watertight Door Safety Function After Routine Passage. Description: As discussed in NRC Integrated Inspection Report 05000456/2012005; 05000457/2012005, a Green finding and associated NCV of 10 CFR 50, Appendix B, Criterion V, Instructions, Procedures, and Drawings, was identified after the inspectors determined that the licensees guidance that permitted operators to leave the diesel oil storage tank (DOST) room watertight flood doors open and unattended for up to 15 minutes to perform tours, inspections, walkdowns, sampling, or other routine tasks in the DOST rooms was inappropriate. The licensee addressed this NCV by revising the guidance that allowed the doors to be left open and unattended. During this inspection period, the inspectors became aware that the licensee re-revised the guidance to again allow the DOST doors to be open for longer than the time needed for routine passage based upon a change to the current licensing basis that eliminated the consideration of a circulating water system line break as an initiating event. The inspectors reviewed the licensees corrective actions and associated 10 CFR 50.59 evaluation that implemented this change and determined that the 10 CFR 50.59 failed to evaluate: An individual who failed to shut one of the watertight flood doors upon identification of a turbine building internal flooding event. Specifically, if an individual failed to shut one of the flood doors, then a loss of safety function could occur because the barrier separating the two DOST rooms was not designed as a flood barrier and both trains of DOST transfer pumps could become submerged, a condition that the equipment is not qualified for. Depending upon the flooding event, stress could potentially affect the overall success of a plant workers required action to close the DOST watertight door. If the DOST flood doors were seismically qualified in the open position. Particularly, the licensee had not evaluated if the DOST flood doors could still be shut following a design basis loading event (e.g., safe shutdown earthquake). If any of the Safety Category II SSCs could fail or fail in a manner that prevented an open DOST flood door from shutting. Based on the above, the inspectors questioned whether the EDG fuel oil transfer system could have been considered operable with the DOST flood doors open and unattended for any period of time other than routine passage. At the end of the inspection period, the licensee had not completed their 10 CFR 50.59 review. Therefore, this URI will remain open pending the licensees completion of that review and additional inspector review. (URI 05000456/201400303; 05000457/201400303, Corrective Actions to Address NCV 05000456/201200501; 05000457/201200501, Failure to Maintain Watertight Door Safety Function After Routine Passage)
05000456/FIN-2014003-01Braidwood2014Q2Issues That Could Adversely Affect the UHSUnresolved Item: Issues That Could Adversely Affect the Ultimate Heat Sink Introduction: The inspectors identified four potential issues of concern after the licensee discovered that station procedures to address a failure of the Braidwood cooling lake dike did not include steps to secure nonsafety-related pumps, although the UFSAR stated and design calculations assumed that all circulating water pumps and nonsafety-related service water pumps would be secured.15. Description: Issue 1: TS 3.7.9, Ultimate Heat Sink, Limiting Condition for Operation Applicability After Identifying that a Non-Conforming Condition Could Challenge and/or Exceed the Associated Ultimate Heat Sink 30 Day Mission Time. The Braidwood cooling lake dike allows the ultimate heat sink (UHS) level to be maintained greater than the TS minimum level of 590. A failure of this nonsafety-related dike would cause a loss of level in the UHS to the 590 TS minimum level. During the inspection period, the licensee discovered that station procedures to address a failure of the Braidwood cooling lake dike did not include steps to secure nonsafety-related pumps, including circulating water pumps and service water pumps, that take a suction from the UHS and discharge to a location outside the UHS. As a result, and because the UFSAR stated and design calculations assumed that all nonsafety-related pumps, including circulating water pumps and service water pumps, would be secured to conserve UHS inventory following a dike failure, a non-conforming condition was identified. The licensee concluded that this non-conforming condition did not render the UHS inoperable as discussed in IR 1675291, Unanalyzed Condition Identified During IR 1674557, and IR 1676076, Discrepancy in the UFSAR Ultimate Heat Sink Description (Section 2.4.11.6), based upon the following: The issue was process-related and only concerned future planned actions for increasing the maximum UHS temperature; All TS 3.7.9, Ultimate Heat Sink, surveillance requirements were met; The Braidwood cooling lake did not actually reach the minimum TS level of 590; A cooling lake dike failure did not actually occur; and A statement in the UFSAR concerning the ability of the UHS to handle an assumed loss-of-coolant-accident coincident with a design basis seismic event that the licensee believed was erroneous. Specifically UFSAR Section 2.4.11.6, Ultimate Heat Sink Design Requirements included the following statement: ...The essential service water cooling pond (ESCP) is an excavated area located within the cooling pond designed to provide a sufficient volume to permit plant operation for a minimum 30-day period without requiring makeup water in accordance with Regulatory Guide 1.27. The ESCP has been reviewed to determine its ability to handle the total heat dissipation requirement of the station assuming a loss of coolant accident (LOCA) coincident with a loss of offsite power on one unit and a concurrent orderly shutdown and cooldown from maximum power to cold shutdown of the other unit using normal shutdown operating procedures, a single active failure, a coincident design basis seismic event... The inspectors noted that IR 1674557, Question on Ultimate Heat Sink License Amendment Request Impact on Pumps, documented that the licensee had preliminarily determined that operation of a single nonsafety-related service water pump at full flow would deplete the UHS in about 3.6 days and, as a result, the UHS would not be able to satisfy the 30-day post-accident volume requirements required by the plants design basis. The licensee concluded that even though procedural guidance did not 16 explicitly direct that nonsafety-related pumps be secured following a design basis accident, operators would recognize the problem and take actions to ensure that the UHS would still be able to perform its safety function and meet all design basis requirements. At the end of the inspection period, the licensee planned to more formally document the bases for UHS TS operability consistent with the definition of operability in the site-specific TSs and the licensees Operability Determination procedure. The licensee subsequently corrected this non-conforming condition by revising procedures to secure nonsafety-related pumps upon reaching a low lake level condition consistent with plant design calculations. Therefore, the inspectors did not have a current operability concern. Issue 1 will remain open pending the completion of the inspectors review of the licensees past operability determination. Issue 2: Timeliness of Actions to Inform the Shift Manager and/or Unit Supervisor of an Issue that May Affect Ultimate Heat Sink Operability On June 25, 2014, the inspectors reviewed IR 1674557, which documented that AOP BwOA ENV3, Braidwood Cooling Lake Low Level, did not direct nonsafety-related pumps that take a suction from the UHS and discharge outside of the UHS to be secured following a dike failure. In particular, although the Operability section of IR 1674557 was left blank, the Reviewed section concluded the following: There were no equipment deficiencies identified. This is a process issue regarding future planned actionsthere are no TS/Technical Requirements Manual/Offsite Dose Calculation Manual/GOCAR (General Operation Corrective Action Requirement) actions applicable; reportability criterion affected; or any SSC (structure, system and component) availability or functionality concerns raised by this issue. The inspectors determined that although the context of IR 1674557 suggested that this issue only impacted future planned actions that, in fact, the issue could affect the current operability of the UHS. Therefore, the inspectors promptly discussed this issue with the Operations Shift Manager who was not aware of any operability concerns associated with the issue or station actions to address the issue. Later that shift, the Shift Manager determined that the issue was reportable under 10 CFR 50.72(b)(3)(ii)(B), Unanalyzed Condition. At the end of the inspection period, it was not clear if the station had adhered to OPAA108115, Operability Determinations to inform the Shift Manager and/or Unit Supervisor of this issue in a timely manner. Issue 2 will remain open pending the licensees completion of a timeline of events and an inspector review of the station standards and implementation of those standards for this issue. Issue 3: Implementation of Operations Standing Order Upon Reaching a Low Lake Level Condition Without Performing a 10 CFR 50.59 and/or Generic Letter 8610 Review17. Upon discovery of the non-conforming and unanalyzed condition of the UHS, the licensee implemented an operations standing order that directed the nonsafety-related service water system, fire protection water system, and circulating water system to be secured following a cooling lake dike failure and low lake level of 590. This operations standing order augmented AOP BwOA ENV3, which did not direct any of these actions. In developing the subject standing order, the licensee did not perform a 10 CFR 50.59 evaluation and/or an associated review in accordance with Generic Letter 8610, Implementation of Fire Protection Requirements. At the end of the inspection period it was not clear if the licensees standing order process, or any other process, permitted this type of change without performing a 10 CFR 50.59 and/or associated Generic Letter 8610 evaluation. Additionally, it was not clear if the licensees temporary change was adequate (i.e. tripping both units, securing all circulating water and non-essential service water system pumps, and securing all running Fire Protection pumps just prior to reaching a low lake level of 590). Issue 3 will remain open pending the licensees completion of a timeline of events and additional inspector review. Issue 4: Safety Category II Structure, Systems and Component Interaction with the Ultimate Heat Sink The turbine building and a number of systems and components within the turbine building are designated as Safety Category II SSCs. The licensee defined Safety Category II SSCs as SSCs that were not designed to Safety Category I Standards. Specifically, Braidwood UFSAR Section 3.2.1.2 defined Safety Category II as follows: Those SSCs which are not designated as Safety Category I are designated as Safety Category II. This category has no public health or safety implication. Safety Category II structures, systems, and components are not specifically designed to remain functional in the event of the safe shutdown earthquake or other design-basis events (including tornado, probable maximum flood, operating basis earthquake, missile impact, or an accident internal to the plant). A reasonable margin of safety is, however, considered in the design as dictated by local requirements. Many Safety Category II items in Category I buildings are supported with seismically designed supports. These items and their supports are not Safety Category I or Seismic Category I as defined by Regulatory Guide 1.29. Structures and major components not listed in Table 3.2-1 as Safety Category I are Safety Category II. Safety Category II systems or portions of systems and components do not follow the requirements of Appendix B to 10 CFR 50. The quality assurance standards for these systems and components follow normal industrial standards and any other requirements deemed necessary by the Licensee. The licensee determined that a circulating water system line break and/or main condenser expansion joint rupture was not credible based on a review of postulated safe shutdown earthquake loads, and therefore a failure of this system following a design basis event such as a safe shutdown earthquake was not within the current licensing basis. The inspectors identified that a failure of the Safety Category II circulating water system could impact safety. For example the Braidwood cooling lake dike was also a Safety Category II structure. A failure of the cooling lake dike and establishment of the UHS18 level of 590 followed by a circulating water line break/expansion joint failure in the turbine building would result in a condition not currently evaluated (i.e., less useable UHS volume due to the displacement of a fraction of the UHS volume into the turbine building). At the end of the inspection period it was not clear how a Safety Category II SSC such as the circulating water system could be credited in a manner to not fail during a safe shutdown earthquake or other associated design basis event since, by definition, Safety Category II SSCs are not specifically designed to remain functional during these events. Additionally, the inspectors planned to review the Safety Category II Lake Screen House structure design to ensure that it could not adversely affect the intake in a manner that would prevent the UHS from performing its intended safety function. Issue 4 will remain open pending NRC review to ensure that the licensee is in compliance with their current licensing basis. (URI 05000456/201400301; 05000457/201400301, Issues That Could Adversely Affect the UHS)
05000389/FIN-2014002-03Saint Lucie2014Q1Failure to Provide Detailed Work Instructions Resulted in Degraded Debris Filter System Performance and resulted in a Manual Reactor TripA self-revealing finding was identified for the licensees failure to provide adequate work instructions. The maintenance work instructions for a debris filter system (DFS) backwash valve motor operator did not contain adequate details to ensure the motor operator was installed correctly. The incorrectly installed motor operator prevented the DFS from mitigating an influx of algae into the circulating water system and ultimately resulted in the need for operators to manually trip the reactor. The licensee entered this issue into the corrective action program (CAP) as action requests (ARs) 1878615 and 1911638. Corrective actions included properly installing the DFS backwash valve motor operator. The performance deficiency was more than minor because it was associated with the equipment reliability attribute of the initiating events cornerstone and adversely affected the cornerstone objective to limit the likelihood of those events that upset plant stability and challenge critical safety functions during power operations. Specifically, the 1A2 DFS backwash valve was installed incorrectly in August 2012. This degraded the components ability to mitigate an algae intrusion event on May 31, 2013, and resulted in a manual reactor trip. The finding was determined to be of very low safety significance (Green) based on Exhibit 1, Initiating Events Screening Questions, found in Inspection Manual Chapter 0609, Significance Determination Process, Appendix A, SDP for Findings At- Power (June 19, 2012). This was due to the fact that the finding did not cause a loss of mitigation equipment relied upon to transition the plant from the onset of the trip to a stable shutdown condition. The cause of this finding was associated with a cross-cutting aspect of providing complete and accurate documentation in the documentation component of the human performance area. Specifically, the licensee did not provide work instructions with enough detail to properly reinstall the1A2 backwash valve motor operator (H.7).
05000373/FIN-2013004-01LaSalle2013Q3Failure to Follow Procedure Led to Manual Scram with ComplicationsA self-revealed finding preliminarily determined to be of low-to-moderate safety significance was identified for the licensees failure to follow procedure LOP-CW-10, Dewatering the Circulating Water System, Revision 32, on Unit 2. Specifically, on April 25, 2013, with Unit 2 at 56 percent power, operators appointed to plan and execute the dewatering of the main condenser waterbox did so in a manner inconsistent with procedural guidance by manually adjusting the circulating water isolation valves while condenser manways were still open. The subsequent loss of isolation led to the flooding of the condenser pit and a resultant circulating water pump trip, loss of the normal heat sink, and a reactor scram. The licensee entered this issue into its corrective action program (CAP) as action report (AR) 1506809 and performed a root cause analysis to identify the root and contributing causes of the event, as well as to determine the appropriate corrective actions, such as providing training and revising procedures. The inspectors determined that the licensees failure to follow the prescribed steps of procedure LOP-CW-10 was a performance deficiency warranting a significance determination. The inspectors used Inspection Manual Chapter (IMC) 0609, Appendix A, The Significance Determination Process (SDP) for Findings At-Power, Exhibit 1, dated June 19, 2012, for the Initiating Events cornerstone. Because the finding caused a reactor trip AND the loss of mitigation equipment relied upon to transition the plant from the onset of the trip to a stable shutdown condition, a detailed risk evaluation was required. The Senior Reactor Analysts (SRAs) used the LaSalle Standardized Plant Analysis Risk (SPAR) model to perform the detailed risk evaluation. In accordance with Risk Assessment of Operational Events Handbook guidance, the initiating event Loss of Condenser Heat Sink was set to 1.0 using the events and condition assessment module of the Systems Analysis Program for Hands-On Integrated Reliability Evaluations (SAPHIRE), Version 8. The calculated conditional core damage probability for the event was 1.6E-6, which represents a finding of low-to-moderate safety significance (White). The finding had a cross-cutting aspect in the area of human performance, decision-making, because the licensee failed to use conservative assumptions when planning and executing the dewatering evolution. Specifically, the incorrect assumption that this evolution performed at-power could be treated the same as when performed during a shutdown condition enabled operators to stray from strict procedure adherence and into knowledge space.
05000456/FIN-2013002-05Braidwood2013Q1NonSafety-Related Turbine Building Waste Disposal System to Safety-Related Essential Service Water Pump Room Sump Design InteractionOn January 21, 2013, the licensee documented in IR 1465027, 1WF040A Not Seating Properly, that SX sump pump discharge check valves 1WF040A and/or 1WF040B might be leaking by based on data that indicated that when the TB sump pump(s) operated, the Unit 1 and Unit 2 A train SX pump room sump pump(s) would start shortly after. This condition suggested that the TB sump pump(s) were filling the Unit 1 and Unit 2 A train SX sump to a level that caused the SX sump pump(s) to start. The licensees prompt operability evaluation was documented in IR 1473152, Single Point Vulnerability for SX Pump Room Flooding, and concluded that the SX pumps were operable since the SX pump room sump pumps can pump water out of the SX pump room sumps and, therefore, prevent water from accumulating in the SX pump room. However, the inspectors noted that previous IRs indicated degraded performance of both A train SX pump room sump pumps (IR 1426946, 1WF06PB Does Not Develop Adequate Discharge Pressure, and IR 1464644, 1WF06PA and B Degraded Insufficient Urgency to Correct. ) On February 13, 2013, the licensee updated their operability review to credit isolating the TB from the SX pump rooms by closing nonsafety-related isolation valves 1WF055 and 2WF055 until the final operability evaluation was complete. On February 14, 2013, the licensee documented that alarm response procedure BwAR OPL02J-2-A6, TB Floor Drain Sump Level High High, was being revised to provide operator direction to align the SX pump room sump to the Radioactive Waste system in the event of TB flooding. Additionally, credit was given to the nonsafety-related SX pump room sump high level alarm to alert operators to an off-normal level condition. The licensee credited the SX pump room sump pumps to be able to pump against the head pressure from the flood water in the TB, though reference was not given to their degraded condition. Issue Report 1473152 referenced UFSAR 10.4.5, Circulating Water System, and identified that the worst case flood in the TB could theoretically reach 396 feet. The lowest elevation of the SX sump pumps was 322 feet. The IR stated that the discharge of the SX room sump pumps was given as 100 gpm at 106 feet which would prevent inflow from the TB. The IR also stated that the NRC Standard Review Plan (SRP) requirement to prevent flooding of a safety-related area was maintained. On March 18, 2013, WO 1497423 was performed and identified that the disc for 1WF040B (SX sump discharge check valve) was stuck in the mid-position. NRC SRP 3.6.1, Plant Design for Protection Against Postulated Piping Failures in Fluid Systems Outside Containment, BTP SPLB 3-1 B.3.b, stated, In analyzing the effects of postulated piping failures, the following assumptions should be made with regard to the operability of systems and components: (1) Offsite power should be assumed to be unavailable if a trip of the turbine-generator system or reactor protection system is a direct consequence of the postulated piping failure; (2) A single active component failure should be assumed in systems used to mitigate consequences of the postulated piping failure and to shut down the reactor, except as noted in Item B.3.b.(3) below. The single active component failure is assumed to occur in addition to the postulated piping failure and any direct consequences of the piping failure, such as unit trip and loss of off-site power (LOOP). Additionally, SRP 9.3.3, Equipment and Floor Drainage System, required that the equipment and floor drainage system be capable of preventing a backflow of water that might result from maximum flood levels to areas of the plant containing safety-related equipment. SRP 10.4.5, Circulating Water System, required compliance with General Design Criteria 4, Environmental and Dynamic Effects Design Bases, based on meeting the following: 1) Means should be provided to prevent or detect and control flooding of safety-related areas so that the intended safety function of a system or component will not be precluded due to leakage from the Circulating Water system; and 2) Malfunction or a failure of a component or piping of the Circulating Water system including an expansion joint should not have unacceptable adverse effects on the functional performance capabilities of safety-related systems or components. Based on the above, the inspectors questioned whether the failure of the 1WF040B check valve would result in water from a postulated TB flood to backflow into the common Unit 1 and Unit 2 A train SX pump room sumps resulting in the loss of the 1A and 2A SX Pumps. The inspectors were unable to determine during the inspection whether the licensees justification was acceptable and therefore this issue will be considered an URI pending further NRC review.
05000285/FIN-2013011-02Fort Calhoun2013Q1Two Examples of Failure to Obtain Prior NRC Approval for Flooding Mitigation StrategiesThe inspectors identified two examples of a Severity Level IV violation of 10 CFR 50.59, Changes, Tests and Experiments, and associated Green findings for the licensees failure to appropriately perform written evaluations for two changes for flooding mitigation strategies. In the first example, the licensee changed the Updated Safety Analysis Report and Abnormal Operating Procedure 01 (AOP-01), Acts of Nature, to incorporate use of backflow through the circulating water system for a flow path for raw water. In the second example, the licensee was implementing a flooding mitigation modification which would have used components which did not meet full quality requirements for their Safety Class 3 designated function. Had the licensee appropriately evaluated these two changes, they would have determined that a license amendment was required for implementation of both changes since both resulted in more than a minimal increase in the likelihood of occurrence of a malfunction of a system, structure, or component important to safety. The failure to perform adequate written evaluations of changes in accordance with 10 CFR 50.59(d)(1) was a performance deficiency. This performance deficiency was of more than minor safety significance because it was associated with the human performance attribute of the mitigating systems cornerstone and it adversely affected the cornerstone objective to ensure the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences. In accordance with the NRC Enforcement Policy, the inspectors used MC 0609, Significance Determination Process, Appendix A, Exhibit 2, to determine the final significance of the finding. For the back flow through the circulating water system example, the finding represented a potential loss of the intake structure due to flooding; therefore, a Phase 3 evaluation by a senior reactor analyst was necessary. The senior reactor analyst evaluated a bounding risk analysis case which assumed that the raw water system and offsite power were lost. This bounding case had an incremental conditional core damage probability of 5.0 x 10-7, and therefore the finding was determined to have very low safety significance (Green). For the trash rack blowdown modification example, the inspectors determined the finding was of very low safety significance (Green) because the finding was a design deficiency that did not result in the loss of functionality. The NRCs significance determination process (SDP) considers the safety significance of findings by evaluating their potential safety consequences. The traditional enforcement process separately considers the significance of willful violations, violations that impact the regulatory process, and violations that result in actual safety consequences. Traditional enforcement applied to this finding because it involved a violation that impacted the regulatory process. Assessing the violation in accordance with Enforcement Policy, the inspectors determined it to be of Severity Level IV because it resulted in a condition evaluated by the SDP as having very low safety significance (Example 6.1.d.2 of the NRC Enforcement Policy). The inspectors determined the Green finding had a cross-cutting aspect in the area of problem identification and resolution because the licensee failed to thoroughly evaluate problems such that resolutions address the causes and extent of condition specifically associated with deficiencies involving the Acts of Nature procedural guidance.
05000285/FIN-2012012-03Fort Calhoun2012Q4Failure to Properly Manage the Functionality of the River Sluice GatesThe team identified a finding exemplified by multiple violations for the failure to manage the functionality of the river sluice gates. Specifically, the licensees preventive maintenance program requirements were not appropriately implemented for a period of 6 months and as a result, the functionality of the river sluice gates was improperly maintained. The examples were: 1. A licensee identified violation of 10 CFR 50, Appendix B, Criterion V, Instructions, Procedures and Drawings, for the failure to perform preventive maintenance required to demonstrate the functionality of the river sluice gates. An NRC identified violation of 10 CFR 50, Appendix B, Criterion V, Instructions, Procedures and Drawings, for the failure to accomplish activities affecting quality in accordance with prescribed instructions when in September 2012, the licensee failed to test the C and D river sluice gates in accordance with station procedure SAO-12-001, to properly maintain functionality of the river sluice gates. 2. An NRC identified violation of 10 CFR 50, Appendix B, Criterion V, Instructions, Procedures and Drawings, for the failure to accomplish activities affecting quality in accordance with prescribed instructions when the licensee failed to test all six gates in October 2012, to maintain functionality of the river sluice gates in accordance with station procedure SAO-12-001. 3. An NRC identified violation of 10 CFR 50, Appendix B, Criterion XVI, Corrective Actions, for the licensees failure to properly identify and timely enter conditions adverse to quality into the Corrective Action Program following multiple failures of the river sluice gates. 4. An NRC identified violation of 10 CFR 50.65, Requirements for Monitoring the Effectiveness of Maintenance at Nuclear Power Plants, for the licensees failure to demonstrate effective control of performance of the circulating water system river sluice gates and failure to place the system in (a)(1) when system performance deteriorated. 5. An NRC identified violation of 10 CFR 50, Appendix B, Criterion V, Instructions, Procedures and Drawings, for the failure to accomplish activities affecting quality in accordance with prescribed instructions when the licensee failed to make the appropriate functionality assessment when the circulating water river sluice gates failed to close during the August 2012 monthly test. The licensee entered these issues into their Corrective Action Program under various CRs described in the body of this report. The team concluded that the failure to manage the functionality of the sluice gates was a performance deficiency that warranted further evaluation. Specifically, the licensees preventive maintenance program requirements were not appropriately implemented for a period of 6 months and as a result, the functionality of the sluice gates was improperly maintained. Using the guidance in IMC 0612, Power Reactor Inspection Reports, Appendix B, Issue Screening, the inspectors determined this finding affected the Mitigating Systems cornerstone. The finding is greater than minor because it is associated with both of the Mitigating Systems Cornerstone attributes of Equipment Performance and Protection Against External Factors and, it adversely affects the associated cornerstone objective of ensuring the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences. The significance of this finding is bounded by the significance of a related Yellow finding regarding the ability to mitigate an external flooding event (Inspection Report 05000285/2010008). The inspectors determined the finding had a cross-cutting aspect in the area of problem identification and resolution because the licensee did not take appropriate corrective action to address safety issues and adverse trends in a timely manner, commensurate with their safety significance and complexity.
05000416/FIN-2012008-07Grand Gulf2012Q3Potential Internal Flooding Caused by Circulation Water System FailureThe inspectors reviewed Calculation M6.3.051, Circulating Water System-Calculate Revised Plant Flooding Elevations Due to Aux Cooling Tower, Revision B, to verify that the postulated failure of circulating water system components in the turbine building would not affect safety-related equipment required for achieving safe shutdown. This calculation assumes that the entire inventory of the circulating water system, 13.4 million gallons, is released into the Unit 1 turbine building due to a circulating water system failure and determines the resulting flood elevations. The calculation does not consider postulated flood flow rates; it is a steady state calculation based on the total circulating water system inventory being contained within the plant buildings. The calculation includes an assumption that the Unit 2 turbine building volume would be available to accommodate floodwater because the passage/corridor between the Unit 1 and Unit 2 turbine buildings is not watertight. In addition, the maximum flood elevation is calculated based on the volume of the radwaste building being available to accommodate floodwater. The sliding door between the Unit 1 turbine building and the radwaste building is not addressed in the calculation. Based on these assumptions, the calculation determines that the bounding flood elevation is 104.0 feet, and that the flood will not reach safety-related equipment located in the control building at elevation 111 feet. The calculation also determines that the bounding flood elevation would reach 111.4 feet in the control building if the volume of the Unit 2 turbine building were not considered. These calculated flood elevations do not include the additional volume contributed by 23,200 gallon per minute makeup from the plant service water system to the circulating water system. The calculation concludes that operator action to stop the makeup flow within 70 minutes is acceptable due to the margin available in the calculation. The inspectors questioned the assumptions of this calculation; especia!ly the assumption that buildings by passageways that are not watertight flood coincidently with each other. The inspectors asked if the expected leak rate between Unit 1 turbine building, Unit 2 turbine building, and the radwaste building through large sliding doors would be sufficient to limit the maximum flood elevation in the control building which is connected to the Unit 1 turbine building with a conventional door. During the inspection, the licensee performed Calculation M6.3.051-001, Circulating Water Systems - Calculate Revised Unit 1 Turbine Building and Unit 1 Control Building Flooding Elevations, Revision O. This calculation was performed to address the inspectors\\\' questions documented in Condition Report CR-GGN-2012-9424. This calculation was a transient analysis of the flood level considering the closed sliding doors between the Unit 1 turbine building and the Unit 2 turbine building and the Unit 1 turbine building and radwaste building. The calculation considered the gaps around the closed doors, and included the contribution of the makeup flow from the plant service water system to the circulating water system. However, Calculation M6.3.051-001, revision 0 was based on a limited flowrate from an expansion boot failure in the circulating water system. The calculation used the methodology of NRC Branch Technical Position MEB 3-1 to predict the maximum flow from a failed circulating water system expansion joint. Applying the MEB 3-1 methodology to the 10-foot diameter expansion joint results in a postulated crack of feet long and i-inch wide. This crack results in a calculated flowrate of approximately 15,500 gpm. Based on this limited flowrate, the calculation determined that the maximum flood elevation would be approximately 104 feet. The inspectors question the applicability of NRC Branch Technical Position MEB 3-1 to nonsafety-related expansion joints and asked the licensee to determine the maximum flood flowrate that would not exceed a flood elevation of 111 feet. In response to these questions, the licensee performed an informal analysis and determined that a flowrate of approximately 75,000 gpm or greater would result in exceeding a flood elevation in the Unit 1 turbine building, potentially communicating with the control building. The licensee also stated that they considered the application of the MEB 3-1 methodology to the expansion joints to be consistent with their licensing basis (UFSAR Section 3.6a.2.1) and that a gross failure of the expansion joint is highly unlikely since the expansion joint in reinforced with steel belts and leakage would be through a local defect. They also stated that the metal shield covering the expansion joints would serve to limit flow from the expansion joint failure, but did not provide the expected flowrate from a large failure of an expansion joint within the metal shield. The inspectors performed a review of licensing basis documentation related to flooding resulting from failures of circulating water components and did not identify any specific value for the maximum flood flowrate or the maximum postulated failure size in an expansion joint. Grand Gulf Nuclear Station Update Safety Analysis Report, Section 10.4.5.3, describes the potential of the entire volume of the circulating water system flooding the Unit 1 turbine building, discusses a potential gross failure in the circulating water system, and describes the maximum circulating water system flowrate but does not specifically address the maximum postulated flood flowrate from a circulating water system failure. The inspectors determined that design basis calculation M6.3.051, Revision B did not adequately verify that the postulated failure of circulating water system components in the turbine building would not affect safety-related equipment required for achieving safe shutdown. This steady state calculation did not consider the effects of closed doors on the maximum flood level in the control building. Calculation M6.3.051-001, Revision 0 was a transient analysis that did address the effects of the closed doors. However, this calculation was based on calculating a limited flood flowrate by applying the methodology of NRC Branch Technical Position MEB 3-1 to non safety-related circulating water system expansion joints. The inspectors were not able to determine if this methodology was consistent with the licensing basis during the period of the inspection. Resolution of this issue will require determining the maximum flowrate resulting from the postulated failure of a circulating water system component in the turbine building and verifying that the resulting flood elevation will not affect safetyrelated equipment required for achieving safe shutdown. The inspectors have discussed this design and licensing basis issue with NRC staff in the Office of Nuclear Reactor Regulation. Due to complexity of establishing the appropriate design and licensing bases for this issue, this item is considered unresolved pending further NRC review to determine if a finding exists. This will be tracked as URI 05000416/2012008-07, Internal Flooding Caused by Circulation Water System Failure.
05000333/FIN-2011004-01FitzPatrick2011Q3Unplanned Power Reduction PI ReportingThe inspectors identified an unresolved item (URI) associated with FitzPatrick staff\\\'s interpretation of guidance for reporting unplanned power changes per 7,000 critical hours. Specifically, Entergy personnel did not report three power reductions during the second quarter of 2011 that the inspectors considered to have been reportable. The unplanned power changes per 7,000 critical hours performance indicator is defined as the number of unplanned changes in reactor power of greater than 20 percent of full-power, per 7,000 hours of critical operation excluding manual and automatic scrams. On January 11, 2011, FitzPatrick operators performed a power reduction to 55 percent to plug a leaking condenser tube. This power reduction was reported in the first quarter performance indicators as an unplanned power change. The root cause evaluation of this event determined that additional condenser tube leaks could occur. As a result, an operational decision-making issue (ODMI) action plan was developed by Entergy staff, which established four action levels for chemistry parameters (condensate demineralizer influent (COl) conductivity, reactor water conductivity, and reactor water chloride concentration). These action levels provide guidance for operators to perform a range of actions, such as a power reduction to support condenser tube plugging. The action plan was established on April 4, 2011. On May 6, 2011, operators observed indications of a rapid increase in hotwell conductivity and determined that COl conductivity increased to above action level 3. In accordance with the ODMI action plan operators reduced power to 55 percent later that day to identify and plug the leaking main condenser tube. The inspectors reviewed the guidance for reporting performance indicators in NEI 99-02, Regulatory Assessment Performance Indicator Guideline, Revision 6. Concerning unplanned power reductions per 7,000 critical hours, the guidance states, This indicator captures changes in reactor power that are initiated following the discovery of an offnormal condition. If a condition is identified that is slowly degrading and the licensee prepares plans to reduce power when the condition reaches a predefined limit, and 72 hours have elapsed since the condition was first identified, the power change does not count. If, however, the condition suddenly degrades beyond the predefined limits and requires rapid response, this situation would count. In follow-up questions regarding the May 6 down power Entergy staff indicated that the down power was planned as a contingency action in the ODMI action plan and that, because the initial condition for which the action plan was written occurred greater than 72 hours prior to the down power, the down power should not be counted. The inspectors considered that notwithstanding an action plan, the condition was best described as a suddenly degrading condition that resulted in operators decreasing power the same day to address the condition. Therefore, it appeared to be appropriate to report the May 6 down power as unplanned. In addition, the inspectors determined that FitzPatrick operators performed two power reductions to 75 percent on June 7, and June 9, 2011, to support cleaning main condenser water boxes. This cleaning was necessary to address fouling that occurred during planned maintenance on the lake intake travelling screens. The fouling was the result of operation of circulating water system gates which caused sediment to be ingested by the circulating water system. The inspectors determined that FitzPatrick staff did not report these two down powers as unplanned in the second quarter PI. The inspectors reviewed the applicable guidance in NEI 99-02 which indicated that Anticipated power changes greater than 20 percent in response to expected environmental problems (such as accumulation of marine debris, biological contaminants, animal intrusion, environmental regulations, or frazil icing) may qualify for an exclusion from the indicator. The licensee is expected to take reasonable steps to prevent intrusion of animals, marine debris, or other biological growth from causing power reductions. Intrusion events that can be anticipated as a part of a maintenance activity or as part of a predictable cyclic behavior would normally be counted, unless the down power was planned 72 hours in advance ... FitzPatrick\\\'s staff indicated they considered this allowance to be applicable, in that they had taken reasonable steps to prevent intrusion by cleaning the lake water forebays prior to the maintenance. Because this activity had not been performed on line since the traveling screens had been replaced, station personnel also considered that they could not reasonably have anticipated the severity of the fouling that occurred. Finally, FitzPatrick staff included a contingency down power in the work week schedule, and noted in the applicable operating procedure that operation of the gates may require a power reduction to perform condenser cleaning. Notwithstanding an acknowledgement by FitzPatrick staff in their procedures and work week schedule as to the possibility of a need for a plant down power, the inspectors considered that these two down power conditions were anticipated as part of a maintenance activity and appeared to have not been planned 72 hours in advance. Therefore the inspectors had questions as to the appropriateness of not reporting the plant down powers on June 7, and June 9,2011. FitzPatrick staff initiated a review of these issues as part of the NRC and industry performance indicator frequently asked questions (FAQ) process. This item remains unresolved pending further information from the FAQ process. (URI 05000333/2011004-01, Unplanned Power Reduction PI Reporting)
05000445/FIN-2011003-01Comanche Peak2011Q2Inadequate External Flooding InstructionsThe inspectors identified a noncited violation of 10 CFR Part 50, Appendix B, Criterion III, for the failure to have adequate external flooding instructions. The licensees technical requirements manual included circulating water system stop gates as a flood protection measure. This statement was not accurate for a reservoir level greater than 778 feet. As a result, the licensee failed to provide specific instructions for flood protection during circulating water system maintenance with stop gates in place. In addition, during service water travelling screen replacement, the licensee failed to provide adequate guidance to mitigate debris from entering the service water pump suctions if water level were to increase above 778 feet. As a result, the service water system was susceptible to fouling during a flooding event. The licensee entered the finding into the corrective action program as Condition Report CR-2011-004062. The licensees failure to have adequate external flooding instructions that resulted in safety related equipment being vulnerable to external flooding was a performance deficiency. The performance deficiency was more than minor because it was associated with the protection against external factors attribute of the initiating events cornerstone 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. Using NRC Manual Chapter 0609, Attachment 4, Phase 1 - Initial Screening and Characterization of Findings, the finding was determined to involve equipment designed to mitigate an external flood and could result in a plant trip or affect more than one train of safety equipment and required a Phase 3 analysis. A senior reactor analyst determined that the finding was of very low safety significance because the calculated bounding delta core damage frequency was 1.9E-8. The finding has a human performance crosscutting aspect associated with decision-making because the licensee failed to demonstrate that nuclear safety is an overriding priority when faced with unexpected plant conditions.
05000266/FIN-2010005-06Point Beach2010Q4Failure to Document a 10 CFR 50.59 Evaluation For Changes Made to Procedure OI-38, Circulating Water System OperationA Severity Level IV non-cited violation of 10 CFR 50.59(d)(1), Changes, Tests, and Experiments, was identified by the inspectors for the failure to document an evaluation that provided a basis for the determination that the changes made to procedure OI-38, Circulating Water System Operation, did not require a license amendment. Specifically, the licensee failed to provide an evaluation that adequately documented that differences between the procedure changes modifying the operational configuration of the condenser steam dump system and operational considerations and design assumptions outlined within the final safety analysis report and the basis of technical specifications were acceptable. As part of its corrective action, the licensee revised the procedure to remove the original change to the operational configuration of the steam dump system. The violation was determined to be more than minor because the inspectors could not reasonably determine that the changes would not have ultimately required prior NRC approval. Violations of 10 CFR 50.59 are dispositioned using the traditional enforcement process instead of the Reactor Oversight Process Significance Determination Process (SDP) because they are considered to be violations that could potentially impede or impact the regulatory process. The underlying technical issue was evaluated under the SDP to determine the significance of the violation with respect to core damage probability. The issue screened as having very low safety significance because the inspectors answered no to all of the questions in the SDP worksheet. The finding has a cross-cutting aspect in the corrective action program element of problem identification and resolution because the licensee failed to thoroughly evaluate questions regarding differences between the plant operational configuration and assumptions in the current licensing basis when they did not complete a prompt operability evaluation to assess noted operational disparities.
05000266/FIN-2010005-07Point Beach2010Q4Failure to Document a 10 CFR 50.59 Evaluation For Changes Made to Procedure OI-38, Circulating Water System OperationA Severity Level IV non-cited violation of 10 CFR 50.59(d)(1), Changes, Tests, and Experiments, was identified by the inspectors for the failure to document an evaluation that provided a basis for the determination that the changes made to procedure OI-38, Circulating Water System Operation, did not require a license amendment. Specifically, the licensee failed to provide an evaluation that adequately documented that differences between the procedure changes modifying the operational configuration of the condenser steam dump system and operational considerations and design assumptions outlined within the final safety analysis report and the basis of technical specifications were acceptable. As part of its corrective action, the licensee revised the procedure to remove the original change to the operational configuration of the steam dump system. The violation was determined to be more than minor because the inspectors could not reasonably determine that the changes would not have ultimately required prior NRC approval. Violations of 10 CFR 50.59 are dispositioned using the traditional enforcement process instead of the Reactor Oversight Process Significance Determination Process (SDP) because they are considered to be violations that could potentially impede or impact the regulatory process. The underlying technical issue was evaluated under the SDP to determine the significance of the violation with respect to core damage probability. The issue screened as having very low safety significance because the inspectors answered no to all of the questions in the SDP worksheet. The finding has a cross-cutting aspect in the corrective action program element of problem identification and resolution because the licensee failed to thoroughly evaluate questions regarding differences between the plant operational configuration and assumptions in the current licensing basis when they did not complete a prompt operability evaluation to assess noted operational disparities.
05000298/FIN-2010004-01Cooper2010Q3Failure to Adequately Monitor the Performance of the Screen Wash SystemThe inspectors identified that the licensee failed to correctly determine that a plant power reduction caused by a clogged screen wash system for the circulating water system was a maintenance preventable functional failure that exceeded the plant level performance criteria. As a direct consequence, the licensee failed to assess this Maintenance Rule Program function per 10 CFR 50.65(a)(1) as required by station procedures. This issue was determined to involve a noncited violation of 10 CFR 50.65(a)(2) requirements for monitoring the effectiveness of maintenance at nuclear power plants. The licensee entered this issue in their corrective action program as CR-CNS-2010-05631. This finding is more than minor because failure to monitor the effectiveness of the screen wash system function CW-F01 affects the protection against external factors attribute of the initiating events cornerstone, since this system was intended to limit the likelihood of events that upset plant stability. The inspectors determined that this performance deficiency was an additional, but separate consequence of the obstructed screen wash system. The inspectors determined that this finding occurred as a separate consequence of the licensees functional failure assessment process, and that the system performance problem was not directly attributable to this finding. Therefore, this finding cannot be processed through the significance determination process, and was determined to be green using the guidance of Appendix B to Manual Chapter 0612 and Appendix D to Inspection Procedure 71111.12. The finding has a crosscutting aspect in the area of human performance associated with decision-making because the licensee did not use conservative assumptions in the functional failure evaluation of an obstructed screen wash system (H.1(b))
05000237/FIN-2010003-06Dresden2010Q2Failure To Perform An Adequate Inspection of Circulating Water Valve 3-4402-COn January 22, 2010, a finding of very low safety significance was self-revealed for failure to perform an adequate inspection of the grease condition of the 3-4402-C valve actuator HBC gear box, which was contrary to the requirements of MA-AA-723-301,Periodic Inspection of Limitorque Model SMB/SB/SBD-000, Revision 3. No violation of regulatory requirements occurred because valve 3-4402-C 2 Enclosure was a nonsafety-related component. The licensee planned to drill inspection ports into and/or replace the HBC gear boxes for valves 2/3-34403-A(B)(C)(D) and 2/3-34402-A(B)(C)(D) and 2-34402-C and change the preventive maintenance requirement to perform a 12 year mechanical inspection of the HBC gear box. This finding was placed in the licensees corrective action program as IR 1034444, Failure of the 3-4402-C Condenser Inlet Valve. The finding was determined to be more than minor because the finding could be reasonably viewed as a precursor to a significant event. Specifically, valve 3-4402-C acted as an inlet in the circulating water system for the south water box. When the valve failed, it was almost completely closed. Had the valve failed open, circulating water would have been diverted from the condenser potentially causing a loss of vacuum that would have resulted in a reduction in power and/or a turbine trip and reactor trip. 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, Initiating Events Cornerstone Column, Transient Initiators question 1, does the finding contribute to both the likelihood of a reactor trip and the likelihood that mitigation equipment or functions will not be available, was answered no, and, therefore, screened as Green. This finding had no cross-cutting aspect due to the issues involved in this valve failure were not indicative of current performance.
05000361/FIN-2009005-07San Onofre2009Q4Inadequate Circulating Water System Maintenance Procedures Contribute to Unit 2 Inadvertent Reactor TripThe inspectors identified a finding for the failure of maintenance personnel to use the standards described in Procedure SO23-XV-2, Troubleshooting Plant Equipment and Systems, in developing procedures and work plans to adequately perform, test, and communicate maintenance activities on Unit 2 circulating water gate 5. Specifically, from September 5 through September 13, 2009, maintenance personnel did not have adequate procedures in place to perform corrective maintenance on Unit 2 circulating water gate 5. The attempts to repair gate 5 were repeatedly unsuccessful due to inadequate planning, execution, postmaintenance testing, and communication. This finding was entered into the licensees corrective action program as Nuclear Notifications NNs 200580999 and 200718204. The finding is greater than minor because the performance deficiency was a precursor to a significant event (reactor trip). Using the Manual Chapter 0609, Significance Determination Process, Phase 1 Worksheets, the finding is determined to have very low safety significance because the finding did not contribute to both the likelihood of a reactor trip and the likelihood that mitigation equipment or functions would not be available. The finding has a crosscutting aspect in the area of human performance associated with work control because maintenance personnel failed to incorporate actions to 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)) (Section 4OA3)
05000456/FIN-2009003-07Braidwood2009Q2Bryozoan Infestation at the lake Screenhouse Circulating Water forebaysThe inspectors identified a NCV of 10 CFR 50, Appendix B, Criterion XVI, Corrective Action Program, having very low safety significance, associated with the licensee\'s failure to identify a significant condition adverse to quality and to develop corrective actions to prevent recurrence. Specifically, the licensee failed to identify the October 2005 bryozoa infestation as a significant condition adverse to quality and did not establish corrective actions to preclude recurrence. This was evidenced by the September 2008 accumulation of bryozoan colonies in the SX and Circulating Water System forebays that resulted in the SX system strainer plugging and hence represented a challenge to the reliability and operability of the SX system. The licensee entered this performance deficiency into their corrective action program. The finding is greater than minor because the failure to identify the significant condition adverse to quality and to develop corrective actions to prevent recurrence affected the Mitigating Systems Cornerstone objective of ensuring the availability, capability and reliability of the Unit 1 and Unit 2 SX trains to respond to initiating events to prevent undesirable consequences. The finding is of very low safety significance because based on the results of an analysis performed by the licensee, which concluded that, even under severely degraded flow conditions, the affected trains of SX would have provided sufficient cooling to components served by the SX system following a reactor trip, a loss of coolant accident, or a loss of offsite power. The primary cause of the finding was related to the cross-cutting element of Human Performance and the associated attribute of decision making (H.1(b)).
05000282/FIN-2008007-01Prairie Island2008Q4Failure to Perform a 10 CFR 50.59 Evaluation for Bulk Hydrogen Storage FacilityThe inspectors identified a Severity Level IV NCV, having very low safety significance, of 10 CFR 50.59, Changes, Tests, and Experiments, for the licensees failure to perform a safety evaluation associated with installation of a bulk hydrogen storage facility. Specifically, the licensee had not evaluated the adverse affects on the Circulating Water System from a postulated hydrogen tank explosion in the bulk storage facility located directly above buried Circulating Water System return lines. The licensee stopped work on the installation of the bulk hydrogen facility and documented the NRC identified issues in the corrective action system. The inspectors concerns also prompted the licensee to identify above ground Cooling Water System pipe in the nearby Turbine Building, which had not been evaluated in the hydrogen blast analysis. The finding was more than minor because the inspectors could not reasonably determine that this change would not have ultimately required prior approval from the NRC. This finding was categorized as Severity Level IV because the underlying technical issue for the finding was determined to be of very low safety significance based on a Phase 1 screening in accordance with IMC 0609, Appendix A, Significance Determination of Reactor Inspection Findings for At-Power Situation. Specifically, the inspectors answered No to the Mitigating Systems screening questions in the Phase 1 Screening Worksheet because the licensee had not yet filled the bulk storage facility with hydrogen, so no possibility of explosion and damage to plant equipment existed. The cause of the finding is related to the cross-cutting element of Human Performance Decision Making, because the licensee failed to make conservative assumptions in decision making associated with the effects of a postulated hydrogen tank explosion (IMC 305, Section 06.07.c, Item H.1(b)). (Section 1R17.1.b
05000219/FIN-2007005-04Oyster Creek2007Q4Loss of a Condenser Vacuum and Trip of a Feedwater Pump Results in a Reactor SCRAMOn December 19, 2007, a reactor power reduction to approximately 50% was commenced to perform planned maintenance on the reactor recirculation pump MG sets and to find and repair condenser tube leaks in the A north water box. Shortly after reducing power to 55%, the plant experienced a loss of vacuum in the A condenser and a trip of the A reactor feedpump due to low suction pressure. Operations personnel responded in accordance with abnormal operating procedures ABN-14,Loss of Condenser Vacuum, and ABN-17, Feedwater System Abnormal Conditions; and performed a manual reactor scram (shutdown) due to the plant conditions. Specifically, the B reactor feedwater pump was removed from service during the power reduction per operating procedures; and with only the C reactor feedwater pump in service, operators performed a manual scram per abnormal operating procedure ABN-17 guidance. Operators mitigated the reactor scram and stabilized the plant in accordance with abnormal operating procedure ABN-1, Reactor Scram and emergency operating procedure (EOP) EMG-3200.01A, RPV Control - No ATWS. Operations personnel and equipment responded as expected during the event. The plant was maintained in hot shutdown while investigation into the cause of the event was determined. At the time of the event, Oyster Creek was operating with two of its four circulating water pumps in-service. In accordance with AmerGens environmental plan and work management schedule for the downpower, the circulating water system was reduced to two pump operation to maximize discharge water temperatures and to minimize the thermal shock impact to aquatic life in the discharge canal during winter conditions. AmerGens preliminary investigation (IR 713652) into the cause of the event determined that two circulating water pump operation, combined with draining of the A north water box, resulted in degraded condenser vacuum, reduced performance of the A condensate pump, and the subsequent trip of the A reactor feedwater pump on low suction pressure. AmerGen reported this event to the NRC in Event Notification 43854, Manual Reactor Scram Due to Lowering Reactor Level. The inspectors responded to the control room following site announcement of a loss of condenser vacuum and observed the response of AmerGen personnel to the event, including operator actions in the control room. At the time of the event, the inspectors verified that conditions did not meet the entry criteria for an emergency action level (EAL) as described in the Oyster Creek EAL matrix. In addition, the inspectors reviewed 10 CFR 50.72, Immediate Notification Requirements for Operating Nuclear Power Reactors, to verify that AmerGen properly notified the NRC during the event. The inspectors also reviewed technical specification requirements to ensure that Oyster Creek operated in accordance with its operating license. This also included a review of Oyster Creeks environmental technical specifications and AmerGens environmental discharge permit NJ0005550 (issued by New Jersey Department of Environmental Protection) due to the impact on the aquatic life (fish) due to the unplanned shutdown. The inspectors reviewed PPC data, control room logs, and discussed the event with AmerGen personnel to gain an understanding of how operations personnel and plant equipment responded during the event. The inspectors evaluated AmerGens program and process associated with event response to ensure they adequately implemented station procedures OP-AA-108-114, Post Transient Review and OP-AA-106-101-1001, Event Response Guidelines. The inspectors also observed the PORC meeting prior to plant startup to evaluate whether AmerGen understood the cause of the event and appropriately resolved issues identified during the event. The inspectors reviewed AmerGens post-trip review report (IR 713652) to gain additional information pertaining to the event, and ensure that human performance and equipment issues were properly evaluated and understood prior to plant startup. No findings of significance were identified. An unresolved item (URI) was identified to review AmerGens corrective action program root cause evaluation (IR 714203) regarding the manual reactor scram on December 19, 2007. The inspectors plan to review this evaluation after it is completed, which had not occurred by the end of this inspection period. (URI 05000219/2007005-04, Loss of A Condenser Vacuum and Trip of A Feedwater Pump Results in a Reactor Scram)
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