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05000280/FIN-2018003-01Surry2018Q3Failure to Control a Modification on the Containment Spray SystemAn NRC-identified Green non-cited violation (NCV) of 10 CFR Part 50, Appendix B, Criterion III, Design Control, was identified for the licensees failure to control the modification for installation of a drain line on the Unit 1 A Containment Spray (CS) pump bearing housing. This resulted in the drain line being blocked by boric acid and inoperability of the Unit 1 A CS pump.
05000454/FIN-2018002-03Byron2018Q2Minor ViolationMinor Violation: The inspectors identified multiple instances of a failure to perform inservice testing in accordance with written procedures appropriate for the circumstances during this inspection period: 1. On March 30, 2018, the licensee performed 1BOSR 5.5.8.DO2, Test of the Diesel Oil Transfer System, and declared the 1B diesel oil transfer pump inoperable due to flow results being low out of specification. Subsequently, the licensee determined that the instrument setup was incorrect in that an incorrect value was entered into the flow meter for pipe diameter. The licensee declared the surveillance invalid and scheduled a time to re-perform the activity. Acceptable system flow rates were achieved a week later when the correct pipe diameter was used for the instrument setup. 2. On April 26, 2018, while observing the licensee perform 2BOSR 5.5.8.CS.52C, Comprehensive Inservice Testing (IST) Requirements for Containment Spray Pump 1CS01PB, the inspectors noted that the pump suction pressure and discharge pressure test gauges were not installed as described in the Precautions and Limitations section of the procedure. After the inspectors asked how the installed configuration satisfied the procedure requirement, the licensee suspended the test to obtain clarification. After some deliberation between engineers and operators attempting to identify the correct instrument location, the test data was recorded with the instruments at different locations for data gathering and comparison. The licensee verified that pump performance had sufficient margin, including the introduced error, to remain operable and available to perform its safety-related function as expected.3. On May 1, 2018, while observing the licensee perform 2BOSR 5.5.8.SX.51C, Comprehensive Inservice Testing (IST) Requirements for the Essential Service Water (SX) Pump 2SX01PA and Unit 2 SX Pumps Discharge Check Valves, the inspectors noted that operators were not taking data from the ultrasonic flow meter in accordance with the procedure. Specifically, the instrument was not set up to indicate time and flow so that an average flow could be determined as required by a Note in the procedure. Instead the operators were recording instantaneous flowrate. When the inspector asked for clarification and the operators and technicians deferred to their supervisors, the licensee suspended the test to obtain clarification. The test was performed again after the instrument was set up correctly and operators were briefed on how to obtain the correct data.Title 10 CFR Part 50, Appendix B, Criterion V, Instructions, Procedures, and Drawings, requires, in part, that activities affecting quality shall be prescribed by documented instructions of a type appropriate to the circumstances and shall be accomplished in accordance with these instructions. Contrary to the above, for the diesel fuel oil transfer pump surveillance, 1BOSR 5.5.8.DO2, the procedure listed an incorrect pipe diameter value that was subsequently entered into the flow meter resulting in unacceptable test results; for the containment spray pump surveillance, 2BOSR 5.5.8.CS.52C, the licensee potentially introduced an unaccounted for error in the surveillance test method by not setting up test equipment in accordance with the procedure; and for the SX surveillance, 2BOSR 5.5.8.SX.51C, the licensee introduced a potential error in the surveillance test by not determining an average flow rate as discussed in the procedure Note.Screening: The failure to perform inservice testing in accordance with written procedures appropriate for the circumstances was a performance deficiencyin each of the listed 11 examples. The performance deficiency was determined to be minor in each case because the inspectors answered No to all of the more-than-minor screening questions in IMC 0612, Appendix B. The licensee generated the following issue reports (IRs) to document these issues:AR 04121539, Ultrasonic Flow Measurement Installation IssueAR 04122295, PCR (procedure change request) 1/2BOSR 5.5.8.DO1 AR 04131201, Engineering Clarification Needed on ASME Precaution AR 04133585, NRC ID: Potential Concerns With Execution of 2A SX Pump Surveillance Violation: These failures to comply with 10 CFR Part 50, Appendix B, Criterion V, Instructions, Procedures, and Drawings, constituted minor violations that are not subject to enforcement action in accordance with the NRCs Enforcement Policy
05000390/FIN-2017004-01Watts Bar2017Q4Misapplication of Technical Specification Limiting Condition for Operation 3.0.6(Opened) Unresolved Item 05000390/2017004-01, Misapplication of Technical Specification Limiting Condition for Operation 3.0.6 Introduction. Inspectors identified an unresolved item (URI) associated with the misapplication of LCO 3.0.6 from the licensees TS as it pertains to the functionality of engineering safety feature (ESF) coolers serving as non-TS support equipment. The item is unresolved pending the outcome of engineering analyses being performed by the licensee to determine if the ESF coolers are necessary for TS-supported systems to maintain operability. In April 2010, TVA revised the bases for the Watts Bar Unit 1 TS by adding language to expand the scope of LCO 3.0.6. The licensee evaluated the TS bases revision against the 10 CFR 50.59 criteria and determined a license amendment was not required for the change.Prior to the TS bases revision, LCO 3.0.6 provided an exception for entering a supported systems conditions and required actions due to the inoperability of a TS support systemwhich by definition is a support system that has an associated LCO in the TS. Following the TS bases revision, the scope of LCO 3.0.6 was expanded to allow another exception pertaining to non-TS support systems (i.e., support systems with no associated LCO)that are 100 percent redundant and have the capability of individually supporting both TS trains. Specifically, the revision allows both of the supported TS trains to be considered operable when one of the 100 percent redundant, non-TS support system trains is declared non-functional (i.e., the non-TS support systems do not have to meet the single failure criterion resulting in the TS systems not meeting the same criterion). This revision to the TS bases manifests itself in the operation of both Unit 1 and Unit 2 ESF coolers that serve as 100 percent redundant, non-TS support systems for both trains of a TS system such as the emergency core cooling system (ECCS), containment spray (CS) system, and CCS. There are 12 plant areas with redundant trains of ESF coolers that support both trains of a TS system. In support of maintenance and in accordance with operating procedure 0-SOI-30.05, TVA routinely removed one of the redundant coolers from service exposing the twotrains of supported TS equipment to a single failure vulnerability. When the plant was in this configuration, the licensee considered both trains of the supported TS systems to be operable, and a TS LCO condition was not entered. The licensee justified operating in this manner based upon the interpretation of LCO 3.0.6, as previously discussed.Inspectors reviewed control room logs and identified multiple occasions where the plant was operated in this manner. In response, the inspectors reviewed the licensing basis for Watts Bar and determined there was a discrepancy between: (1) the General Design Criteria (GDC) found in Chapter 3 of the facilitys UFSAR; and (2) the operation of TS systems with the single failure criterion not being met.The GDC that pertain to ECCS, CS, and CCS all contain a requirement that the system safety function can be accomplished assuming a single failure. Inspection IMC 0326, Operability Determination & Functionality Assessments for Conditions Adverse to Quality or Safety (Agencywide Documents Access & Management System (ADAMS)Accession Number ML15328A099) contains guidance for inspectors to assist their review of licensee determination of operability and resolution of degraded or nonconforming conditions. IMC 0326 specifies that failure to meet a GDC is an entry point for an operability determination. Also, based on the definition of operability, IMC 0326 states: The operability requirements for an SSC (structure, system, and component) encompass all necessary support systems (per the TS definition of operability) regardless of whether the TS explicitly specify operability requirements for the support functions. In response to this inspection discovery, the licensee took two actions. First, in the nearterm, TVA revised the applicable ESF cooler operating procedure to require entrance into the appropriate LCO condition and required action statement when one of the ESF cooler trains is nonfunctional. Secondly, while the current design bases for the affected systems indicates that the coolers are required for system operability, TVA is performing engineering evaluations to determine if the support requirement can be eliminated under certain conditions. This effort is being tracked in TVAs corrective action program by CR 1357258. Based on the ongoing engineering evaluations, the inspectors have characterized this issue as a URI pending the outcome of the results. Once the evaluations are finalized, additional inspection can be performed to determine if a PD actually exists (e.g., TS violation). This is identified asURI 05000390/2017004-01, Misapplication of Technical Specification Limiting Condition for Operation 3.0.6.
05000282/FIN-2017004-03Prairie Island2017Q4Licensee-Identified ViolationPrairie Island TS LCO 3.0.3 requires, in part, that when an LCO is not met and an associated ACTION is not provided, action shall be initiated within 1 hour to place the unit in MODE 3 within 7 hours.Contrary to the above, at 1556 hours on May 4, 2016, the licensee failed to place Unit 2 in MODE 3 within 7 hours due to no associated ACTION provided within TS 3.6.5, Containment Spray and Cooling Systems for two containment cooling trains not OPERABLE. Specifically, between May 4 and May 5, 2016, operators failed to recognize that with the ongoing unplanned inoperability of the 122 control room chiller, and the subsequent unplanned inoperability of the A train #23 CFCU, the 122 control room chiller was a required support system for the B train #22 and #24 CFCUs. Therefore, with both of the Unit 2 CFCU trains inoperable, LCO 3.0.3 was required to be entered to place Unit 2 in Mode 3 within 7 hours. Because the supported system TS applicability was not recognized, LCO 3.0.3 was not entered as required and both trains of Unit 2 CFCUs were inoperable for approximately 35 hours.Because the inspectors answered No to questions B.1 and B.2 under Exhibit 3, Barrier Integrity Screening Questions of IMC 0609, Appendix A, The Significance Determination Process (SDP) for Findings at Power, the finding screened as very low safety significance (Green). The issue was entered into the licensees CAP as CAP 501000002726. Corrective actions included re-assessing shared system LCOs between Units 1 and 2, revising the LCO tracking database, implementing new standards for LCO 3.0.6 applications, and revisions to the Safety Function Determination Program.
05000261/FIN-2017007-03Robinson2017Q4Failure to Determine Most Severe Containment Spray pHThe NRC identified a non-cited violation of 10 CFR Part 50.49, Environmental qualification of electric equipment important to safety for nuclear power plants, for the licensees failure to correctly determine the most severe composition of chemicals for containment spray for the purposes of environment al qualification of equipment in containment. Specifically, the licensee did not identify that the pH of the chemical spray could have been more severe than what was identified in the Environmental Qualification zone maps if the Spray Additive Tank (SAT) had been operated at its limits provided in procedures CP-001 and OST- 023. In response to this issue, the licensee placed the issue into their corrective action program as NCR 2162081, demonstrated operability by reviewing current and historical operating conditions of the tank, and implemented administrative controls to prevent exceeding the qualified pH limit. This performance deficiency was more than minor because if left uncorrected, the performance deficiency had the potential to lead to a more significant safety concern. Specifically, the containment spray pH could have exceeded the pH to which equipment inside containment was qualified, if the SAT had been operated at its procedural limits. The inspectors determined the finding to be of very low safety significance (Green) because the finding was a deficiency affecting the design or qualification of a mitigating structure, system, or component (SSC), and the SSC maintained its operability or functionality. A cross-cutting aspect was not assigned because the finding was not indicative of current licensee performance.
05000255/FIN-2017007-02Palisades2017Q4Containment Spray Pipe Support Strap DeficienciesThe inspectors identified a finding of low safety significance (Green) and an associated potential NCV of Title 10of theCode of Federal Regulations,Part 50, Appendix B, Criterion III, Design Control, for failure to meet Updated Final Safety Analysis Reportrequirements for containment spraypiping supports, specifically straps. Specifically, the inspectors identified that Calculation No. EA-SP-03369-02, Revision 0, used inelastic acceptance limits for the pipe straps which connect the pipe to the pipe support, in order to demonstrate Class I compliance which was not in accordance with the design and licensing basis specification. The license entered the issue into their Corrective Action Programas CR-PLP-2017-05246, Spray Pipe Support,dated November 14, 2017. The licensee performed an analysis to establish reasonable assurance of operability and the inspectors with support from the Office from the Nuclear Reactor Regulation reviewed this operability and no performance deficiencies were identified.The performance deficiency was determined to be more-than-minor because it was associated with the Barrier Integrity Cornerstone attribute of design control and adversely affected the cornerstone objective to provide reasonable assurance that physical design barriers (fuel cladding, reactor coolant system, and containment) protect the public fromradionuclide releases caused by accidents or events. This finding is of very-low safety significance (Green) because there was no actual reactor containment barrier degradation. The inspectors did not identify a cross-cutting aspect associated with thisfinding because this was a legacy design issue; and therefore, was not reflective of current performance.
05000483/FIN-2017003-01Callaway2017Q3Spurious Containment Spray Pump StartThe inspectors reviewed a self -revealed, non- cited violation of Technical Specification 5.4.1.a, Procedures, for the licensees failure to implement Preventative Maintenance Basis document IC-LSELS, Load Shed and Emergency Load Sequencer (LSELS), Revision 0. Specifically, the licensee failed to replace load shed and emergency load sequencer relay driver Card NF039AR06SL23, a Consolidated Controls 6N232 relay driver card, within the scheduled periodicity. On June 28, 2017, containment spray train A pump , PEN01A, spuriously started due to the cards failure. As a result, one train of the containment spray system was rendered inoperable for a total of 44 hours, of which all 44 hours w ere unplanned. As immediate corrective actions, the licensee replaced the circuit card under Job 17002747, completed post -maintenance testing, and restored the system to operable status on June 30, 2017. The licensee entered this issue into the corrective action program under Condition Report 20170 3433. The failure to replace load shed and emergency load sequencer relay driver Card NF039AR06SL23 within the scheduled periodicity was a performance deficiency. This performance deficiency was more than minor , and therefore a finding, because it adversely affected the equipment performance attribute of the Mitigating Systems Cornerstone and its objective of ensuring the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences. Specifically, o n June 28, 2017, containment spray train A pump , PEN01A, spuriously started due to the cards failure. As a result, one train of the containment spray system was rendered inoperable for a total of 44 hours . Using Inspection Manual Chapter 0609, Attachment 4, Initial Characterization of Findings, and Appendix A, The Significance Determination Process (SDP) for Findings At - Power, Exhibit 2, Mitigating Systems Screening Questions, dated June 19, 2012, the inspectors determined the finding was of very low safety significance (Green) because (1) the finding was not a deficiency affecting the design or qualification of a mitigating system; (2) the finding did not represent a loss of system and/or function; ( 3) the finding did not represent an actual loss of function of a single train for greater than its technical specification allowed outage time; and (4) the finding does not represent an actual loss of function of one or more non- technical specification trains of equipment designated as high safety -significant in accordance with the licensees maintenance rule program for greater than 24 hours. Specifically, the total duration of inoperability was 44 hours which is less 3 than the technical specification allowed completion time of 72 hours for this system. The finding had a cross -cutting aspect in the area of problem identification and resolution associated with resolution because the licensee failed to take effective corrective actions to address issues in a timely manner commensurate with their safety significance. Specifically, the licensee did not replace load shed and emergency load sequencer relay driver Card NF039AR06SL23 prior to failure although this issue was documented in corrective actions ranging from April 2008 to January 2017 (P.3).
05000336/FIN-2017002-01Millstone2017Q2Potential Untimely Corrective Action for Anchor Darling Double Disc Gate ValvesThe inspectors identified that Dominion has not implemented corrective actions to address potential substantial safety hazards associated with several safety significant valves at Millstone Unit 2 that was reported in a 10 CFR Part 21 notification letter dated February 25, 2013. Specifically, after establishing a corrective action plan, to date Dominion has not implemented actions to either evaluate or inspect susceptible valves. However, inspectors need to compare actions taken to Dominions CAP requirements and review industry recommendations to address the Part 21 letter to determine if this represents a performance deficiency or violation of NRC requirements. As a result, the NRC has opened an unresolved item (URI) related to this issue of concern. Description. In 2012, Browns Ferry Nuclear Plant Unit 1 experienced a failure of an isolation valve due to a failure of the valve stem to wedge anti-rotation wedge pin as noted in a 10 CFR Part 21 Notification Letter dated January 4, 2013. Subsequent analysis by Flowserve, owner of Anchor/Darling, determined the cause was a manufacturing defect, wherein the wedge pin installation torque was insufficient to meet the design needs of the valve. Flowserve further concluded that other valves of this type, Anchor Darling double disc gate valves in motor operated valve (MOV) applications with Limitorque or Rotork actuators, could be susceptible to similar failures. As documented in the associated 10 CFR Part 21 Notification Letter from Flowserve dated February 25, 2013, Millstone was susceptible to a potential substantial safety hazard due to this potential failure mechanism. Dominion captured this condition in CR504097 and determined that the following Millstone Unit 2 valves were susceptible: CS-4.1A, Containment Spray Header Isolation CS-4.1B, Containment Spray Header Isolation CS-13.1A, RWST Outlet Isolation CS-13.1B, RWST Outlet Isolation CS-16.1A, Containment Sump Outlet Header Isolation CS-16.1B, Containment Sump Outlet Header Isolation The Dominion fleet MOV Program owner accepted the action (CA284339) to establish a corrective action plan on November 21, 2014, approximately 21 months after 10 CFR Part 21 notification by Flowserve. The corrective action plan for the susceptible valves included valve performance monitoring consistent with current MOV program requirements as well as stem position monitoring during travel every cycle which would indicate potential degradation of the wedge pin. Ultimate resolution for each location incorporates valve disassembly, intrusive inspection, and re-torque of the stem/wedge connection to mitigate the notified potential substantial safety hazard. To date, Dominion has not performed stem position monitoring, contrary to their corrective action plan, thereby limiting their capacity to identify wedge pin degradation without assessment of the change. Furthermore, due to the invasive nature of the ultimate resolution as well as the safety functions of the susceptible locations, final corrective actions for each valve must be performed with the unit offline. Dominion initially established ultimate resolution at each location in spring of either 2016 or 2017 without alignment to an outage schedule or cycle plan. On February 16, 2016, because the 2016 valves would be worked during a refueling outage, the facilities safety review committee met, extending due dates until June 1, 2017. Immediately preceding the spring 2017 refueling outage, Dominion realigned ultimate resolution for the susceptible valves to the fall 2018 and spring 2020 refuel outages due to failure to receive parts required to complete contingency maintenance. Ultimately, from February 25, 2013, through the present, the inspectors identified that Dominion delayed implementation of corrective actions for multiple potential substantial safety hazards that was communicated in a 10 CFR Part 21 notification letter. However, inspectors need to compare actions taken to Dominions CAP requirements and review industry recommendations to address the Part 21 letter to determine if this represents a performance deficiency or violation of NRC requirements. (URI 05000336/2017002-01, Potential Untimely Corrective Action for Anchor Darling Double Disc Gate Valves)
05000315/FIN-2017002-05Cook2017Q2Inadequate Design Control Measures to Ensure Leakage Remained Within AnalysisGreen . The inspectors identified a finding of very low safety significance (Green) and an associated NCV of 10 CFR Part 50, Appendix B, Criterion III, Design Control, for the failure to have adequate design control measures verify that the Essential Service Water to Containment Spray (CTS) heat exchanger outlet valves were not leaking in excess of the limits of the Large Break Loss of Coolant Accident (LBLOCA) analysis. This finding was entered into the licensees CAP to evaluate adequate design control measures. The performance deficiency was determined to be more than minor because the finding was associated with the Mitigating Systems cornerstone attribute of design control and affected the cornerstone objective of ensuring the capability of the CTS system to respond to an initiating event to prevent undesirable consequences. The finding screened as of very low safety significance (Green) because it did not result in the loss of operability or functionality of one of the trains of the CTS system. The inspectors did not identify a cross -cutting aspect associated with this finding because it was not reflective of current performance.
05000445/FIN-2017002-06Comanche Peak2017Q2Unanalyzed Condition Involving Potential Moderate Energy Line BreakInspection Scope On September 13, 2016, based on initial observations by NRC inspectors, the licensee determined that pressurized fire protection piping in the service water intake structure was not properly shielded for moderate energy line break protection of service water components which resulted in inoperability of one train of service water for both Unit 1 and Unit 2. During extent of condition walk downs conducted on October 6, 2016, October 10, 2016, November 17, 2016, December 5, 2016, and December 22, 2016, additional piping in the Unit 1 and Unit 2 safeguards and auxiliary buildings was found to not be shielded correctly as well, resulting in inoperability of one train of various safety related equipment for both units. The licensee determined the most likely cause of this event was that the methodology used to conduct the initial moderate energy line break walk downs was flawed and allowed some threats to be missed. The licensees corrective actions include shielding the affected piping, performing a 100 percent walk down of rooms containing moderate energy line break piping identified for shielding, and revising the systems interaction program maintenance procedure. These activities constituted completion of one event follow -up sample, as defined in Inspection Procedure 71153. b. Findings Introduction. The inspectors identified a non- cited violation of 10 CFR Part 50, Appendix B, Criterion III, Design Control, associated with the licensees failure to assure that applicable regulatory requirements and the design bases, as defined in 10 CFR 50.2 and as specified in the license application, for those structure, systems and components to which this appendix applies, were correctly translated into specifications, drawings, procedures, and instructions. Specifically, from initial construction through March 2017, the licensee failed to fully incorporate applicable design requirements for components needed to ensure the capability to shut down the reactor and maintain it in a safe shutdown condition following a moderate energy line break. Description. On September 13, 2016, inspectors performed walkdowns in the service water intake structure and identified a vertical run of unshielded, pressurized fire protection piping that appeared to pose a moderate energy line break threat to the service water pumps. Inspectors determined that in the event of a moderate energy line break crack along any portion of the unshielded piping, the resultant spray had the potential to impact the function of any one of the four service water pumps. However, only one train would have been affected during the event due to the physical configuration/separation relative to the source line and target pumps and/or associated motor control centers that support pump operation. Inspectors informed the licensee of their concern. Engineering personnel performed a subsequent walkdown of the intake structure and determined that the identified piping was not correctly shielded and operability of the service water pumps was in question. The licensee took immediate action to isolate and depressurize the fire protection line in question which addressed the operability concern. The licensee entered this issue into the station corrective action program as Condition Report CR -2016 -008147 for resolution. Part of the licensees actions was to perform extent of condition walkdowns for unshielded moderate energy piping in the safeguards building for Unit 1 and 2. During the extent of condition walk downs conducted on October 6, 2016, October 10, 2016, November 17, 2016, December 5, 2016, and December 22, 2016, additional piping in the Unit 1 and Unit 2 safeguards and auxiliary buildings was found to not be appropriately shielded against a moderate energy line break, resulting in the inoperability of various safety related equipment for both units. Unit 2 Train B 480 VAC motor control center 2EB2- 1 (Unit 2 Train B emergency core cooling, battery charger, containment spray, and containment isolation valve equipment) Unit 1 Train B 480V MCC 1EB4- 2, and Unit 1 Train B Distribution Panel 1ED2- 2 (Unit 1 Train B safety -related pumps, panels, sequencer, and transformers) Unit 1 Train B 480V MCC 1 EB4- 1 (Unit 1 Train B safety -related pumps, valves, fans, battery chargers, and transformers) Unit 2 Train B 480V MCC 2E134- 1 (Unit 2 Train B safety -related pumps, valves, fans, battery chargers, and transformer) Unit 1, Train B 480V MCC 1E84- 1 (Unit 1 Train B safety -related pumps, valves, fans, battery chargers, and transformers) In each of these instances the licensee took prompt action to isolate and depressurize the identified moderate energy piping pending modification. The licensee subsequently determined that the most probable cause of the issue was the use of a flawed methodology during the initial moderate energy piping walkdowns conducted in 1989. The licensee reported this issue to NRC in Event Report 52239, and Licensee Event Report 16 -002- 00. Analyses. The failure to incorporate applicable design requirements into specifications for moderate energy line break protection was a performance deficiency. The performance deficiency was more than minor, and therefore a finding, because it was associated with the design control attribute of the Mitigating Systems cornerstone and affected the cornerstone objective to ensure the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences. Specifically, from initial construction through March 2017, the licensee failed to fully incorporate applicable design requirements for components needed to ensure the capability to shut down the reactor and maintain it in a safe shutdown condition following a moderate energy line break. Using Inspection Manual Chapter 0609, Attachment 04, Initial Characterization of Findings, dated July 1, 2012, and Inspection Manual Chapter 0609, Appendix A , Significance Determination Process for Findings At -Power , Exhibit 2, Mitigating Systems Screening Questions, dated October 7, 2016, the inspectors determined the finding required a detailed risk evaluation because the finding involved a deficiency affecting the design and qualification of a mitigating structure, system, or component, and resulted in a loss of operability, and represented an actual loss of function of at least a single train for longer than its allowed out age time. A senior reactor analysts from Region IV performed a detailed risk evaluation and determined that the bounding increase in core damage frequency for this issue was 5.1E -8/year for Unit 1 and 2.9E -10/year for Unit 2 , and was therefore of very low safety significance (Green). Additional information is included in the detailed risk evaluation in Attachment 3 of this report. The inspectors did not assign a cross -cutting aspect because the performance deficiency was not reflective of present performance. Enforcement. Title 10 CFR Part 50, Appendix B, Criterion III, Design Control, states, in part, that, measures shall be established to assure that applicable regulatory requirements and the design bases, as defined in 10 CFR 50.2 and as specified in the license application, for those structures, systems, and components to which this appendix applies, are correctly translated into specifications, drawings, procedures, and instructions. Contrary to the above, measures established by the licensee did not assure that applicable regulatory requirements and the design bases, as defined in 10 CFR 50.2 and as specified in the license application, for those structures, systems, and components to which this appendix applies, were correctly translated into specifications, drawings, procedures, and instructions. Specifically, from initial construction through March 2017, the licensee failed to fully incorporate applicable design requirements for components needed to ensure the capability to shut down the reactor and maintain it in a safe shutdown condition following a moderate energy line break. This issue does not represent an immediate safety concern because when the lines were identified the licensee took prompt action to isolate and depressurize them, and the licensee has implemented plant modifications. Since this violation was of very low safety significance (Green) and has been entered into the corrective action program as Condition Report CR- 2016- 008147, this violation is being treated as a non -cited violation consistent with Section 2.3.2 of the NRC Enforcement Policy. (NCV 05000445/2017002 -05; 05000446/2017002- 05, Failure to Translate Design Requirements Into the As Built Facility)
05000348/FIN-2017002-02Farley2017Q2Failure to Follow Procedure Resulted in Inoperable PRF System BoundaryThe NRC identified a Green non-cited violation (NCV) of Technical Specification (TS) 5.4.1.a, Procedures, when inspectors found the 1A containment spray (CS) pump room door (door 106) open on May 12, 2017, without the required dedicated individual to close the door. As a result, the penetration room filtration (PRF) system boundary was inoperable which rendered both trains of the PRF system inoperable. Failure to follow section 19.0 of licensee procedure FNP-0-SOP-0.0, Version 163, was a performance deficiency. The performance deficiency was more than minor because it was associated with the structure, system, component and barrier performance attribute of the barrier integrity cornerstone and adversely affected the cornerstone objective to provide reasonable assurance that physical design barriers protec t the public from radionuclide releases caused by accidents or events. Specifically, when door 106 was open, the PRF system boundary was inoperable, which caused both PRF trains to be inoperable. Without the dedicated individual to close the door as directed, the ability of the PRF system to perform its safety function was compromised. The significance of this finding was evaluated using IMC 0609, Appendix A, The Significance Determination Process (SDP) for Findings At-Power, dated June 19, 2012. This finding was of very low safety significance (Green) because the finding only represented a degradation of the radiological barrier function provided for the auxiliary building through the PRF system. The inspectors determined the finding had a cross-cutting aspect of Teamwork in the Human Performance area because maintenance did not effectively communicate and coordinate their activities with operations to ensure the requirements were met when door 106 was left open (H.4).
05000368/FIN-2017002-02Arkansas Nuclear2017Q2Failure to Install Set Screw Leads to Breaker FailureGreen . The inspectors documented a Green self -revealing finding and associated non- cited violation of Unit 2 Technical Specification 6.4.1.a, for failure to properly pre-plan and perform maintenance on the Unit 2 containment spray pump B breaker in accordance with written procedures. Specifically, the licensee failed to install a cam shaft set screw during the breakers last overhaul. The cam eventually became displaced on the shaft, and the breaker failed to close. To correct the issue, the licensee replaced the breaker and installed a cam shaft set screw in the failed breaker. The licensee also inspected all other similar breakers to verify the cams were properly secured. The licensee entered the issue in to their corrective action program as Condition Report CR -ANO -2-2017- 03168. The failure to install a cam shaft set screw during the overhaul of the Unit 2 containment spray pump B breaker is a performance deficiency. The performance deficiency is more than minor because it was associated with the equipment performance attribute of the mitigating systems cornerstone and adversely affected the cornerstone objective to ensure the reliability of systems that respond to initiating events to prevent undesirable consequences. Specifically, the performance deficiency resulted in the failure of a Unit 2 containment spray pump breaker. Using Inspection Manual Chapter 0609, Appendix A, The Significance Determination Process (SDP) for Findings At -Power, dated June 19, 2012, Exhibit 2, Mitigating Systems Screening Questions, the issue screened as having very low safety significance (Green) because it was not a design or qualification deficiency; did not represent a loss of system; did not result in the actual loss of function of a train of technical specification equipment for greater than its allowed outage time; and did not screen as potentially risk significant due to seismic, flooding, or severe weather events. The inspectors determined this finding did not have a cross -cutting aspect because the most significant contributor did not reflect current licensee performance. Specifically, the error occurred during the breakers last overhaul, which occurred in 2011
05000313/FIN-2017001-01Arkansas Nuclear2017Q1Failure to Identify Damaged LugsGreen. The inspectors documented a self-revealing finding and associated non-cited violation of Unit 1 Technical Specification 5.4.1.a, for the failure to properly perform maintenance on the Unit 1 suction valve to the emergency core cooling system B and containment spray B. Specifically, the licensee failed to identify a damaged electrical lug on the valve actuator during maintenance. The lug subsequently failed and the valve failed to stroke fully open after being returned to service. The licensee repaired the lug and restored the valve to service. The licensee documented this issue in Condition Report CR-ANO-1-2017-00270. The licensee failed to identify a damaged electrical lug on a motor-operated valve during maintenance, which is a performance deficiency. The performance deficiency is more than minor because it is associated with the human performance attribute of the mitigating systems cornerstone and adversely affected the cornerstone objective to ensure the reliability of systems that respond to initiating events to prevent undesirable consequences. Specifically, the performance deficiency resulted in the failure of a suction valve for one train of emergency core cooling systems and containment spray systems after the valve was returned to service from the maintenance. Using Inspection Manual Chapter 0609, Appendix A, The Significance Determination Process (SDP) for Findings At-Power, dated June 19, 2012, Exhibit 2, Mitigating Systems Screening Questions, the inspectors determined that the finding required a detailed risk evaluation because the finding represented an actual loss of function of a single train for greater than its technical specification allowed outage time. The analyst determined in a detailed risk evaluation that by combining internal and external event inputs yielded an estimate of the total increase in core damage frequency of 8.5E-7/year, or of very low safety significance (Green). The finding was determined to have a cross-cutting aspect in the area of human performance associated with Avoid Complacency because the primary cause of the performance deficiency involved the failure to plan for the possibility of mistakes and use appropriate error reduction tools. (H.12)
05000335/FIN-2017001-01Saint Lucie2017Q1Inadequate Procedure Results in Adding an Incorrect Lubrication Oil to the 1B CS Motor Inboard BearingAn NRC-identified Green, non-cited violation (NCV) of Technical Specification (TS) 6.8.1, Procedures and Programs, was identified for the licensees failure to establish, implement, and maintain written procedures covering activities referenced in NRC Regulatory Guide 1.33, Revision 2, dated February 1978. Specifically, the licensees failure to maintain a plant lubrication manual with correct lubrication oil specifications for the 1B containment spray (CS) pump motor resulted in adding unacceptably low viscosity lubrication oil to the inboard bearing of the 1B CS pump motor. Immediate corrective actions included restoring the 1B CS pump inboard bearing with the correct lubrication oil and placing the issue in the licensees corrective action program.The licensees failure to correctly specify the 1B CS pump motor inboard bearing lubrication requirements in licensee general maintenance procedure GMP-22 was a performance deficiency (PD). The PD was more than minor because it was associated with the procedure quality attribute of the mitigating systems cornerstone and adversely affected the cornerstone objective to ensure the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences (i.e., core damage). Specifically, the inadequate procedure resulted in adding the incorrect lubrication oil to the 1B CS pump motor bearing, causing the pump to be declared inoperable for approximately 56.5 hours. The finding screened to Green because the failure did not: (1) affect the design or qualification of the systems, structures and components, (2) represent an actual loss of function, and (3) represent an actual loss of function of at least a single train for greater than its TS allowed outage time. The finding involved the cross-cutting area of human performance, in the aspect of avoid complacency, in that, the individuals involved with the procedure revision did not implement appropriate error reduction tools to ensure the procedure was appropriately changed to reflect the new lubrication oil requirement (H.12).
05000461/FIN-2016009-05Clinton2016Q4Failure to Promptly Identify that the Incapability of the RHR Design to Support TS Operability Requirements Was a CAQThe team identified a finding of very-low safety significance (Green) and an associated NCV of Title 10 of the Code of Federal Regulations (CFR), Part 50, Appendix B, Criterion XVI, Corrective Action, for the licensee failure to promptly identify that the incapability of the residual heat removal (RHR) design to support Technical Specifications (TS) operability requirements was a condition adverse to quality. Specifically, when reactor water temperature was greater than 150 degrees Fahrenheit, RHR could not be realigned from shutdown cooling mode of operations to provide the TS required functions of the emergency core cooling system, suppression pool cooling, containment spray, and feedwater leakage control system. The licensee captured this issue in their Corrective Action Program (CAP) as Action Request (AR) 02742439 and AR 03948042, and planned to submit a License Amendment Request to align TS requirements with the design capabilities. The performance deficiency was determined to be more-than-minor because it was associated with the Mitigating Systems cornerstone attribute of design control and adversely affected the associated cornerstone objective of ensuring the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences. Specifically, the performance deficiency resulted in voluntarily declaring TS functions inoperable when performing shutdown cooling operations, which did not ensure the associated mitigating systems availability or capability to respond to an initiating event. The team determined that this finding was of very low safety significance (Green). Specifically, there were no known instances where the finding: (1) represented a loss of system safety function; (2) represented an actual loss of safety function of at least a single train or two separate safety systems out-of-service for greater than their TS allowed outage time; (3) involved non-TS trains of equipment; (4) involved a degradation of a functional RHR auto-isolation on low reactor vessel level; (5) impacted external event protection; or (6) involved fire brigade issues. The team did not identify a cross-cutting aspect associated with this finding because it did not reflect current licensee performance since the performance deficiency occurred more than 3 years ago.
05000255/FIN-2016003-01Palisades2016Q3Failure to Appropriately Select and Review for Suitability of Application the Control Switch and Circuit Design of the Engineered Safeguards Room Cooler FansA self-revealed finding of very low safety significance and an associated non-cited violation (NCV) of Title 10 of the Code of Federal Regulations, Part 50, Appendix B, Criterion III, Design Control, was identified for the failure to appropriately select and review for suitability of application the control switch and circuit design of the engineered safeguards room cooler fans. Specifically, on July 27, 2016, when the licensee was conducting troubleshooting activities for the tripping of engineered safeguards room cooler fan V27B, it was revealed that the control switch design was break before make and as the hand switch was transitioned from one position to the next, the supply voltage and the motor became out of phase and caused an overcurrent trip of the breaker. This resulted in an unplanned entry into a 72 hour limiting condition for operation (LCO) for the right train of the emergency core cooling system (ECCS). In the apparent cause evaluation (ACE) for this issue, the licensee determined that the contributing cause had not previously addressed this particular failure mode (i.e. the control switch and circuit design) when similar overcurrent events occurred in the past. Prior corrective actions included adding guidance to system operating procedures to pause between hand switch movements and replacing other components within those systems. These actions were not successful in eliminating this failure mode. The licensee documented the issue in their CAP, planned to revise the control circuit and switch design, and added specific procedural steps on how to operate these fans until the design change was implemented. The finding was more than minor in accordance with IMC 0612, Appendix B, because it was associated with the Mitigating Systems Cornerstone attribute of Equipment Reliability and adversely impacted the cornerstone objective of ensuring the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences. Specifically, as a result of the overcurrent trip of its breaker, V27B was declared non-functional and unavailable and the equipment in the room it cooled was declared inoperable, which included the A high pressure safety injection (HPSI) pump and the A containment spray (CS) pump. This led to an unplanned entry into a 72 hour LCO for the right train of ECCS. The finding had a cross-cutting aspect in the area of Problem Identification and Resolution and was related to the cross-cutting component of Evaluation, which required that the licensee thoroughly evaluate issues to ensure that resolutions address causes and extent of conditions commensurate with their safety significance. As discussed above, in the ACE for this issue the licensee determined that the corrective actions associated with the identified contributing cause following similar overcurrent events that occurred in the past had not addressed or been successful in eliminating this failure mode (PI.2).
05000454/FIN-2016002-05Byron2016Q2Licensee Implementation of Enforcement Guidance Memorandum 15002, Enforcement Discretion for Tornado-Generated Missile Protection NoncomplianceOn June 10, 2015, the NRC issued Regulatory Issue Summary (RIS) 201506, Tornado Missile Protection, focusing on the requirements regarding tornado-generated missile protection and required compliance with the facility-specific licensing basis. The RIS also provided examples of noncompliance that had been identified through different mechanisms and referenced enforcement guidance memorandum (EGM) 15002 which was also issued on June 10, 2015. The EGM provided guidance to allow the NRC staff to exercise enforcement discretion when an operating power plant licensee did not comply with the current licensing basis for tornado-generated missile protection. Specifically, the discretion applied to SSCs declared inoperable resulting in TS LCOs that would require a reactor shutdown or mode change if the licensee could not meet the required actions within the TS completion time. The discretion allowed the licensee to re-establish operability through compensatory measures and established criteria for continued operation of the facility as longer term corrective actions were implemented. The EGM stated that the bounding risk analysis performed for this issue concluded that this issue was of low risk significance and, in Byrons case, provided for enforcement discretion of up to three years from the date of issuance of the EGM. However, the EGM did not provide licensees with enforcement discretion for any related underlying technical violations; and moreover, the EGM specifically requires that any associated underlying technical violation(s) be assessed through the enforcement process. Appendix A to 10 CFR Part 50, General Design Criteria for Nuclear Power Plants (GDC), Criterion 4, Environmental and Dynamic Effects Design Basis, stated in part that SSCs important to safety shall be adequately protected against dynamic effects including missiles. On May 25, 2016, the licensee initiated IR 02673848, identifying a nonconforming condition of Criterion 4. Specifically, multiple locations were identified in the refueling water storage tank (RWST) roof hatches and in the L-line wall above the 451 elevation (separating the turbine building from the Class I auxiliary building) where SSCs were not adequately protected from tornado-generated missiles. The licensee declared multiple SSCs inoperable and promptly implemented compensatory measures designed to reduce the likelihood of tornado-generated missile effects. The inspectors reviewed the licensees compensatory measures that included: review and revision of procedures for a tornado watch and a tornado warning to provide additional instructions for operators preparing for tornados and/or high winds, and a potential loss of SSCs vulnerable to the tornado missiles; confirmation of readiness of equipment and procedures dedicated to the Diverse and Flexible Coping Strategy (FLEX); verification that training was up to date for individuals responsible for implementing preparation and response procedures; and establishment of a heightened station awareness and preparedness relative to identified tornado missile vulnerabilities. The condition was reported to the NRC as Event Notice (EN) 51958 as an unanalyzed condition and potential loss of safety function. The licensee documented the inoperability of the SSCs and the affected TS LCO conditions in the CAP and in the control room operating log. The shift manager notified the NRC resident inspector of implementation of EGM 15002, and documented the implementation of the compensatory measures to establish the SSCs operable but nonconforming prior to expiration of the LCO required action. The enforcement discretion was applied to the required shutdown actions of the following TS LCOs for both units: TS 3.0.3, General Shutdown LCO (cascading or by reference from other LCOs) TS 3.3.7, Control Room Ventilation (VC) Filtration System Actuation Instrumentation; TS 3.5.2, ECCS Operating; TS 3.5.4, Refueling Water Storage Tank (RWST); TS 3.6.6, Containment Spray and Cooling Systems; TS 3.7.9; Ultimate Heat Sink; TS 3.7.10, Control Room Ventilation (VC) Filtration System; TS 3.7.11, Control Room Ventilation (VC) Temperature Control System; TS 3.8.4, DC Sources Operating; TS 3.8.7, Inverters Operating; and TS 3.8.9, Distribution Systems Operating. The inspectors review addressed the material issues in the plant, and whether the measures were implemented in accordance with the guidance documentation for the EGM. The inspectors also evaluated whether the measures as implemented would function as intended and were properly controlled. The licensee implemented actions to track the more comprehensive actions to resolve the nonconforming conditions within the required 60 days. These comprehensive actions were to remain in place until permanent repairs were completed, which for Byron were required to be completed in three years, or until the NRC dispositioned the non-compliance in accordance with a method acceptable to the NRC such that discretion was no longer needed. The inspectors did not review the underlying circumstances that resulted in the TS violations. As stated in the EGM guidance, violations of other requirements, including 10 CFR 50 Appendix A, Criterion 4, which may have contributed to the TS violations, would be evaluated independently of the EGM implementation. This operability inspection constituted a partial sample as defined in IP 71111.1505 since all corrective actions to support continued operability and resolution of the nonconforming conditions had not been identified. These actions and any underlying technical violations will be addressed with the completion of this inspection sample and documented in a future NRC Inspection Report.
05000255/FIN-2016007-01Palisades2016Q2Failure to Correct Containment Spray Pump Non-conformanceThe team identified a finding of very low safety significance and an associated NCV of 10 CFR Part 50, Appendix B, Criterion XVI, Corrective Action, for the licensees failure to promptly correct a condition adverse to quality. Specifically, the licensee failed to correct a non-conforming condition for containment spray pump P54A, which was discovered in October 2014, during an NRC component design bases inspection (CDBI). The licensee entered this issue into their CAP as CRPLP201601646 with an assigned action to resolve the non-conforming condition of the containment spray pump The team determined that the performance deficiency was more than minor because it was associated with the Mitigating Systems cornerstone attribute of Design Control and adversely affected the cornerstones objective of ensuring the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences (i.e., core damage). Specifically, the performance deficiency identified that the licensee failed to correct a non-conformance between their current as-built configuration, the current licensing bases (i.e., Final Safety Analysis Report (FSAR) Section 6.2.3.1), and the design basis (i.e., Design Basis Calculation EAELECLDTAB005) which was identified by the NRC in the 2014 CDBI. In accordance with IMC 0609, Significance Determination Process, Attachment 0609.04, Initial Characterization of Findings, issued June 19, 2012, and Appendix A, The Significance Determination Process for Findings At-Power, Exhibit 2, Mitigating Systems Screening Questions, issued June 19, 2012, the team answered No to all of the questions. Therefore, this finding was of very low safety significance (Green). The team identified a cross-cutting aspect in the Evaluation component of the Problem Identification and Resolution cross-cutting area because the licensee failed to fully evaluate the original issue identified in the 2014 CDBI to ensure that the corrective actions performed adequately addressed the non-conformance. Specifically, the licensee evaluated the effect of the non-conformance, but failed to correct the underlying non-conformance between the licensing basis, the as-built configuration, and the design basis.
05000456/FIN-2016002-04Braidwood2016Q2Licensee Implementation of Enforcement Guidance Memorandum 15002, Enforcement Discretion for Tornado-Generated Missile Protection NoncomplianceOn June 10, 2015, the NRC issued Regulatory Issue Summary (RIS) 201506, Tornado Missile Protection, focusing on the requirements regarding tornado-generated missile protection and required compliance with the facility-specific licensing basis. The RIS also provided examples of noncompliance that had been identified through different mechanisms and referenced enforcement guidance memorandum (EGM) 15002, which was also issued on June 10, 2015. The EGM provided guidance to allow the NRC staff to exercise enforcement discretion when an operating power plant licensee did not in comply with the current license basis for tornado-generated missile protection. Specifically, the discretion would be applied to structure system and components (SSCs) declared inoperable resulting in TS LCOs that would require a reactor shutdown or mode change if the licensee could not meet the required actions within the TS completion time. The discretion allowed the licensee to reestablish operability through compensatory measures and established criteria for continued operation of the facility as longer term corrective actions were implemented. This allows the licensee to continue operating until final corrective actions are taken in the timelines established in the EGM. The EGM stated that the bounding risk analysis performed for this issue concluded that this issue was of low risk significance and, in Braidwoods case, provided for enforcement discretion of up to 3 years from the date of issue of the EGM. However, the EGM does not provide the licensees enforcement discretion for any related underlying technical violations; and moreover, the EGM specifically requires that any associated underlying technical violation be assessed through the enforcement process. Appendix A to 10 CFR Part 50, General Design Criteria for Nuclear Power Plants (GDC), Criterion 4, Environmental and Dynamic Effects Design Basis, stated in part that SSCs important to safety shall be adequately protected against dynamic effects including missiles. On May 25, 2016, the licensee initiated IR 02673854, identifying a nonconforming condition of Criterion 4. Specifically, multiple locations were identified in the refueling water storage tank (RWST) roof hatches and in the L-line wall above the 451 elevation (separating the turbine building from the Class I auxiliary building) where SSCs were not adequately protected from tornado-generated missiles. The licensee declared multiple SSCs inoperable and promptly implemented compensatory measures designed to reduce the likelihood of tornado-generated missile effects. The inspectors reviewed the licensees compensatory measures that included: review and revision of procedures for a tornado watch and a tornado warning to provide additional instructions for operators preparing for tornados/high winds, and potential loss of SSCs vulnerable to the tornado missiles; confirmation of readiness of equipment and procedures dedicated to the Diverse and Flexible Coping Strategy (FLEX); verification that training was up to date for individuals responsible for implementing preparation and response procedures; and establishment of a heightened station awareness and preparedness relative to identified tornado missile vulnerabilities. The condition was reported to the NRC as Event Notice 51959 as an unanalyzed condition and potential loss of safety function. The licensee documented the inoperability of the SSCs and the affected TS LCO conditions in the CAP and in the control room operating log. The shift manager notified the NRC resident inspector of implementation of EGM 15002, and documented the implementation of the compensatory measures to establish the SSCs operable but nonconforming prior to expiration of the LCO required action. The enforcement discretion was applied to the required shutdown actions of the following TS LCOs for both units: TS 3.0.3, General Shutdown LCO (cascading or by reference from other LCOs); 19 TS 3.3.7, Control Room Ventilation (VC) Filtration System Actuation Instrumentation; TS 3.5.2, ECCS Operating; TS 3.5.4, Refueling Water Storage Tank (RWST); TS 3.6.6, Containment Spray and Cooling Systems; TS 3.7.5, Auxiliary Feedwater System; TS 3.7.10, Control Room Ventilation (VC) Filtration System; TS 3.7.11, Control Room Ventilation (VC) Temperature Control System; TS 3.8.4, DC Sources Operating; TS 3.8.7, Inverters Operating; and TS 3.8.9, Distribution Systems Operating. The inspectors review addressed the material issues in the plant, and whether the measures were implemented in accordance with the guidance documentation for the EGM. The inspectors also evaluated whether the measures as implemented would function as intended and were properly controlled. The licensee implemented actions to track the more comprehensive actions to resolve the nonconforming conditions within the required 60 days. These comprehensive actions were to remain in place until permanent repairs were completed, which for Braidwood were required to be completed in 3 years, or until the NRC dispositioned the non-compliance in accordance with a method acceptable to the NRC such that discretion was no longer needed. The inspectors did not review the underlying circumstances that resulted in the TS violations. As stated in the EGM guidance, violations of other requirements, including 10 CFR 50 Appendix A Criterion 4, that may have contributed to the TS violations would be evaluated independently of the EGM implementation. This operability inspection constituted a partial sample as defined in IP 71111.1505 since all the corrective actions to support continued operability and resolution of the nonconforming conditions had not been identified. These actions and any underlying technical violations will be addressed with the completion of this inspection sample.
05000282/FIN-2016002-01Prairie Island2016Q2Licensee-Identified ViolationPrairie Island TS 3.6.3, Containment Isolation Valves, Required Action A.1 required, in part, isolation of the affected penetration flow path within 4 hours if one or more penetration flow paths with one containment isolation valve inoperable. Contrary to the above, since August 4, 2012 on 21 occasions for Unit 1 and 23 occasions for Unit 2 (three year reporting window), the licensee failed to isolate containment spray header penetration flow paths within 4 hours during the performance of quarterly containment spray pump surveillance procedures SP 1090A & 1090B and SP 2090A & 2090B. Specifically, the SPs inappropriately credited Note 1 of TS 3.6.3 and created open flow paths from the Unit 1 and 2 containments under administrative control while vent and/or drain valves connected to the containment spray header were opened. The opening of these valves was to facilitate draining of the header and to verify no leakage past manual isolation valves during containment spray pump operation in recirculation mode. On August 4, 2015, the licensee generated CAP 01488454 which questioned whether use of TS 3.6.3 Note 1 to open the containment spray header vent and drain valves under administrative control was permissible. The licensee performed an apparent cause evaluation and determined that because the vent and drain valves were not considered part of a containment penetration flow path, Note 1 could not be applied. A past operability review was performed and it was determined that on multiple occasions (at 1-10 hour durations) over the prior three years, the vent/drain opening resulted in a 3/8 opening in the containment pressure boundary. Because the resultant leakage at peak containment pressure during a design basis accident (approximately 4 percent of the containment volume per day) would have exceeded the maximum allowable leakage rate, conditions that could have prevented the fulfillment of the safety function of the Units 1 and 2 containments and, conditions that were prohibited by TS, had occurred. Because the inspectors answered Yes to question B.1 under Exhibit 3, Barrier Integrity Screening Questions of IMC 0609, Appendix A, The Significance Determination Process (SDP) for Findings at Power, the inspectors transitioned to IMC 0609, Appendix H, Containment Integrity Significance Determination Process. Because the leak rate through the vent/drain openings would not have exceeded greater than 100 percent of the containment volume per day at calculated peak containment internal pressure, the finding screened as very low safety significance (Green). The issues were entered into the licensees CAP as CAP 01488454. Corrective actions included immediate quarantine of the affected SPs and subsequent revisions to the SPs and TS Bases.
05000456/FIN-2016001-04Braidwood2016Q1Questions Regarding the Implementation of the Gas Accumulation ProgramQuestions Regarding the Implementation of the Gas Accumulation Progra The inspectors identified an URI regarding the implementation of the Gas Accumulation Program at Braidwood. Specifically, the inspectors were concerned with whether a number of surveillance frequencies that were contained in the Surveillance Frequency Program meet the requirements as specified in procedure ERAA2009, Managing Gas Accumulation. Additionally, the inspectors were concerned with the basis for not increasing the frequency of the UT examinations following the discovery of a void on October 20, 2015. At the end of the inspection period, the licensees investigation on the cause of an unexpected void growth, and the potential surveillance frequency discrepancies was ongoing. Resolution of this issue will be based on the inspectors review of the licensees completed investigation. On March 15, 2016, while performing a semi-annual gas monitoring surveillance on Unit 2 under 2BwOSR 3.2.22, ECCS and Containment Spray Venting and Valve Alignment/UT Verification Surveillance, a gas void was found along line 2SI03BA, which is a SI line that feeds the A and D SI hot leg injection lines. The ultrasonic examination revealed that a 0.960 cubic foot void was present. A void had been previously identified in the same location on October 20, 2015, which had a volume of 0.25 cubic feet. Calculation BRW150100M was performed in October 2015 to justify operability of the SI system. The calculation produced a void size acceptance criteria of 0.389 cubic feet. Upon identification of the void in March 2016, the licensee declared the 2A SI train inoperable due to the previously established acceptance criteria of 0.389 cubic feet not being met, and entered LCO 3.5.2, ECCS Operating, Condition A, which required that the affected train be restored to an operable status within 7 days. The licensee exited the LCO on March 16, 2016 upon completion of a revision to calculation BRW150100M, which documented a revised acceptance criteria of 1.5 cubic feet. During this inspection period, the inspectors reviewed the licensees revision to the aforementioned calculation, and the requirements contained in procedure ERAA2009. Based on their review, the inspectors questioned the basis for not increasing the frequency of the UT examinations following the discovery of the void on October 20, 2015. Additionally, the inspectors were concerned with the frequency of inspection of a number of locations outside the missile barrier (17 for Unit 1 and 19 for Unit 2), which appeared to conflict with what was specified in the procedure. Specifically, the locations in question were examined at an 18 month frequency, although the procedure stated that frequency of once per refueling outage shall be used only for locations that are inaccessible due to actual (not just posted) high radiation conditions. Finally, the inspectors had a concern regarding the means by which gas accumulation was managed for locations inside the missile barrier, since the prescribed locations were only monitored once upon Mode ascension from an outage. The licensee entered the inspectors concerns into their CAP as IR 2644532 and IR 2640751. At the conclusion of the inspection, two work group evaluations were in progress to: 1) address the void growth observed since October 2015, and 2) evaluate the compliance with the program document procedure, ERAA2009. This URI will remain open until the evaluations are completed and the inspectors review the evaluations to determine whether a performance deficiency exists. (URI 05000456/20160104; 05000457/201600104; Questions Regarding the Implementation of the Gas Accumulation Program)
05000285/FIN-2015004-02Fort Calhoun2015Q4Licensee-Identified ViolationTechnical Specification (TS) 2.4(1)a.iv requires that all valves, piping, and interlocks associated with the components of the containment cooling system required to function during accident conditions be operable. In the event that any of these components, required to function during accident conditions become inoperable, the reactor shall be placed in a hot shutdown condition within 12 hours. The containment spray pumps and the associated piping are part of the containment cooling system. Prior to making modifications to containment spray piping in 2015, the operability of this piping would have been challenged by a main steam line break or a loss of coolant accident due to thermal stresses induced in the piping after a rise in containment temperature after the postulated event. Operation prior to the implementation of the modifications was a violation of the technical specification requirements to maintain operability of containment cooling systems. The violation is more than minor because it is associated with the design control attribute of the mitigating systems cornerstone because the failure to anticipate the rise in containment spray piping temperature dates back to the original design of the plant. This adversely affects the cornerstone objective to ensure the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences. The violation was of very low safety significance because although the subject piping was inoperable due to exceeding code specified stress limits, analysis showed that the piping would have been able to perform its safety function to deliver adequate containment spray flow in the event of an accident. The licensee entered the issue into their corrective action program as Condition Report 2015-04578.
05000445/FIN-2015005-07Comanche Peak2015Q4Licensee-Identified ViolationTitle 10 CFR Part 50, Appendix B, Criterion V, Instructions, Procedures, and Drawings, requires, in part, that activities affecting quality shall be accomplished in accordance with documented instructions, procedures, or drawings, of a type appropriate to the circumstances. Station Procedure STI-442.01, Operability Determination and Functionality Assessment Program, Revision 3, an Appendix B quality related procedure, provides instructions for evaluating the operability of safety-related components. Procedure STI-442.01, Step 6.1, requires, in part, that when a potential degraded or nonconforming condition is identified, the shift manager should ensure the operability determination process is initiated to determine the operability of the structure, system or component. Contrary to the above, on July 26, 2015, when a potential degraded or nonconforming condition was identified, the shift manager failed to ensure the operability determination process was initiated to determine the operability of the structure, system or component. Specifically, the licensee failed to adequately assess and demonstrate the operability of Unit 1 train B containment spray system when a degraded condition was identified. Using Inspection Manual Chapter (IMC) 0609, Appendix A, The Significance Determination Process (SDP) for Findings At-Power, dated June 19, 2012, inspectors determined that this finding was of very low safety significance (Green) because the finding: did not involve the loss or degradation of equipment or function specifically designed to mitigate a seismic event, and (1) was not a deficiency affecting the design and qualification of a mitigating structure, system, or component, and did not result in a loss of operability or functionality, (2) did not represent a loss of system and/or function, (3) did not represent an actual loss of function of at least a single train for longer than its allowed outage time, or two separate safety systems out-of-service for longer than their technical specification allowed outage time, and (4) does not represent an actual loss of function of one or more non-technical specification trains of equipment designated as high safety-significant for greater than 24 hours in accordance with the licensees maintenance rule program. The violation was entered into the licensees corrective action program as Condition Report CR-2015-006785.
05000313/FIN-2015004-03Arkansas Nuclear2015Q4Failure to Properly Translate the Design Requirements for the Unit 1 Decay Heat Vault Rooms Being Sealed (The inspectors identified a non-cited violation of 10 CFR Part 50, Appendix B, Criterion III, Design Control, for the failure to correctly translate the regulatory requirements and design basis into specifications, drawings, procedures, and instructions to ensure the Unit 1 decay heat vault boundary components could perform their safety-related function. Inspectors identified that the Unit 1 decay heat vaults had a safety-related function to limit accident dose consequences to the public and the control room operators, but some boundary components had not been classified as safety-related. In response to this issue, the licensee performed an immediate operability determination and reviewed previous leakage testing on the containment spray and low pressure injection systems. This issue was entered into the licensees corrective action program as Condition Report CR-ANO-1-2015-04195. The inspectors determined that the failure to correctly translate the design requirement that the Unit 1 decay heat vaults be sealed to mitigate the dose consequences of an accident into specifications, drawings, procedures, and instructions was a performance deficiency. This performance deficiency was more than minor because it was associated with the design control and safety-related structures, systems, and components and barrier performance attributes of the Barrier Integrity cornerstone and adversely affected the cornerstone objective to provide reasonable assurance that physical design barriers protect the public from radionuclide releases caused by accidents or events for the auxiliary building. Specifically, the licensee failed to ensure that Unit 1 decay heat vault boundary components were designated as safety-related components and met the applicable requirements needed to assure the reliability and integrity of the barrier function. Using Inspection Manual Chapter 0609, Appendix A, Exhibit 3, Barrier Integrity Screening Questions, the issue screened as having very low safety significance (Green) under the Control Room, Auxiliary, Reactor, or Spent Fuel Pool Building questions because the finding only represented a degradation of the radiological barrier function provided for the control room and the auxiliary building and it did not represent a degradation of the barrier function of the control room against smoke or a toxic atmosphere. The inspectors determined that this finding did not have a cross-cutting aspect because the most significant contributor did not reflect current licensee performance since this condition had existed since construction.
05000266/FIN-2015010-01Point Beach2015Q3Failure to Evaluate Containment Spray System for Potential Gas IntrusionThe inspectors identified a finding of very-low safety significance, and an associated NCV of Title 10, Code of Federal Regulations, Part 50, Appendix B, Criterion III, Design Control, for the licensees failure to evaluate for potential gas intrusion from the spray additive tank into the containment spray (CS) system during the injection phase of a design-basis accident. As part of immediate corrective actions, the licensee entered the concern in the Corrective Action Process as AR 2068569, and performed an evaluation which determined no air entrainment is expected to occur during the injection phase. The performance deficiency was determined to be more than minor because it was associated with the Mitigating Systems cornerstone attribute of equipment performance, and affected the cornerstone objective of ensuring the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences. Specifically, air intrusion into the CS system could affect the operability of the CS pumps by causing degraded performance and/or air binding of the pumps. The finding screened as having very-low safety significance. Specifically, the finding was a deficiency affecting the design or qualification of a mitigating structure, system, or component (SSC), however, based on the evaluation performed by the licensee the SSC maintained its operability. Based on the timeframe of the violation the inspectors did not identify a cross-cutting aspect associated with this finding.
05000247/FIN-2015003-05Indian Point2015Q3Licensee-Identified ViolationUnit 2 TS 5.4.1.a requires that the procedures listed in Attachment A to RG 1.33, Quality Assurance Program Requirements, Revision 2, be established and implemented. Attachment A states that instructions should be prepared, as appropriate, for draining and changing mode of operations for containment cooling systems. NEI 07-07, Objective 1.2.2, requires licensees to evaluate work practices, such as draining of systems that involve licensed material and for which there is a credible mechanism for the material to reach groundwater. Contrary to the above, Entergy did not evaluate work practices involving changing the mode of operation and draining of the containment spray system (a containment cooling system) to assure that the drainage did not reach groundwater; and as a result, during the Unit 2 refueling outage in March 2014, the containment spray system was drained to a floor drain which subsequently overflowed, spread on the floor of a piping room, and leaked through the floor to groundwater. The violation was identified by Entergy in their investigation of groundwater activity identified at the end of the outage during planned sampling of monitoring wells on the site. The issue is a finding as it affected the Public Radiation Safety cornerstone, since Entergys actions resulted in an unintended abnormal effluent release. This finding was assessed using IMC 0609D, Public Radiation Safety, and was determined to be of very low safety significance (Green) because the subsequent groundwater release was a very small fraction of routine liquid radioactive effluent releases, and did not represent any significant dose impact to the public. Entergy documented the issue in their investigation evaluation (CR-IP2-2014-2564) and corrected the issue by revising their draining procedure OAP-038, Operations Mechanical Equipment Operating Guidelines, to assure that contaminated fluids are not discharged outside of the selected drain point. Entergy also provided training to operators on expectations during draining evolutions to assure contaminated liquids are properly controlled.
05000454/FIN-2015008-05Byron2015Q3Failure to Adequately Implement a Design Change Associated with the RWSTsThe team identified a finding of very-low safety significance (Green), and an associated NCV of 10 CFR Part 50, Appendix B, Criterion III, Design Control, for the licensees failure to translate applicable design basis into Technical Specifications (TSs) Surveillance Requirement 3.5.4.2 implementing procedures. Specifically, these procedures did not verify the RWST vent line was free of ice blockage at the locations, and during all applicable MODEs of reactor operation assumed by the ECCS and containment spray (CS) pump NPSH calculation. The licensee captured this issue into their CAP to reconcile the affected procedures and calculation. The performance deficiency was determined to be more than minor because it was associated with the Mitigating Systems cornerstone attribute of design control, and affected the cornerstone objective of ensuring the availability, reliability, and capability of mitigating systems to respond to initiating events to prevent undesirable consequences. Additionally, it was associated with the Barrier Integrity cornerstone attribute of design control, and affected the cornerstone objective of providing reasonable assurance that physical design barriers protect the public from radionuclide releases caused by accidents or events. The finding screened as very-low safety significance (Green) because it did not result in the loss of operability or functionality, and it did not represent an actual open pathway in the physical integrity of reactor containment. Specifically, the licensee performed a historical review of the last 3 years of operation, and did not find any instances in which the vent path temperature fell below 35 degrees Fahrenheit. The inspectors did not identify a cross-cutting aspect associated with this finding because it was confirmed not to be reflective of current performance due to the age of the performance deficiency. (Section 1R21.5.b(2))
05000286/FIN-2015003-04Indian Point2015Q3Licensee-Identified ViolationTS 3.6.6, Containment Spray System and Containment Fan Cooler System, requires two containment spray trains and three containment fan cooler trains to be operable in Modes 1, 2, 3, and 4. TS SR 3.6.6.3 verifies that each containment FCU cooling water flow rate is equal to or greater than 1400 gpm every 92 days. Contrary to TS SR 3.6.6.3, during an essential SW header flow balance test in accordance with 3-PT-R200 on March 3, 2015, three of the five FCUs had coolant water flow less than the required 1400 gpm. Engineering was contacted prior to continuing 3-PT-R200 and directed operations to continue and adjust the FCU throttle valves to obtain FCU outlet SW flow at or greater than 1430 gpm (to account for 30 gpm correction factor for instrument error). On April 9, 2015, during a review of anomalous data identified during 3-PT-R200, Entergy engineering determined that the quarterly surveillance test, 3-PT-Q016, EDG and VC Temperature Valves SWNFCV- 1176 and 1176A and SWN-TCV-1104 and 1105, was not performed with the correct SW system alignment. Entergy identified the cause of the condition was improper implementation of improved TS requirements in 2001. Entergy entered this issue into their CAP as CR-IP3-2015-1063 and CR-IP3-2015-2448. The inspectors evaluated this finding using IMC 0609.04, Initial Characterization of Findings, and IMC 0609, Appendix A, Exhibit 3, Barrier Integrity Screening Questions. The inspectors determined that the finding was of very low safety significance (Green) because the finding did not represent a loss of safety function.
05000368/FIN-2015008-02Arkansas Nuclear2015Q2Failure to Correct containment Spray Pump Interlock to Shutdown Cooling Heat Exchanger Room CoolersThe team identified a Green, non-cited violation of 10 CFR Part 50, Appendix B, Criterion XVI, Corrective Action, for the licensees failure to correct a condition adverse to quality. Specifically, the licensee failed to correct the containment spray pump interlock to automatically start the shutdown cooling heat exchanger room coolers. The licensees failure to promptly correct a condition adverse to quality as required by 10 CFR Part 50, Appendix B, Criterion XVI, was a performance deficiency. The licensee has identified in multiple instances since 1989 a degraded or nonconforming condition with shutdown cooling heat exchanger room cooler interlocks, but has failed to correct the condition. This finding was more than minor because it was associated with the design control and equipment performance attributes of the Mitigating Systems cornerstone and adversely affected the cornerstone objective to ensure the availability, reliability, and capability of systems that respond to events to prevent undesirable consequences. Specifically, the licensee failed to correct the interlock feature that automatically starts the room coolers when the pump starts. Using Inspection Manual Chapter 0609, Appendix A, the team determined that the finding was of very low safety significance (Green) because it did not result in the loss of operability or functionality of any system or train and did not screen as risk-significant in response to external events. This finding had a cross-cutting aspect in the area of problem identification and resolution associated with evaluation because the licensee failed to thoroughly evaluate the issue to ensure that the resolution addressed the cause (P.2).
05000368/FIN-2015002-02Arkansas Nuclear2015Q2Failure to Protect Motor Control Center from Potential Pipe SprayThe inspectors identified a Green non-cited violation of 10 CFR Part 50, Appendix B, Criterion III, Design Control, for the failure to select and review equipment for suitability of application that is essential to the safety-related function of Unit 2 motor control center (MCC) 2B-52. Specifically, the licensee failed to ensure that the safety-related electrical equipment inside the MCC was adequately protected from water spray in the event of a failure of overhead non-seismic category 1 pipes, in accordance with the safety analysis report. Inspectors identified that the installed spray curtain only protected the front of the cabinet, while a cooling water pipe that could break during a seismic event was located directly above the length of the MCC. This issue was entered into the licensees corrective action program as Condition Report CR-ANO-C-2015-01342. The failure to protect Unit 2 MCC 2B-52 from possible spray of overhead non-seismic category 1 pipes by installing a spray shield in accordance with the safety analysis report was a performance deficiency. The performance deficiency was more than minor because it was associated with the design control attribute of the Mitigating Systems Cornerstone and adversely affected the cornerstone objective to ensure the reliability of systems that respond to initiating events to prevent undesirable consequences. Specifically, the performance deficiency could result in failure of one train of essential safety features during a seismic event, such as exhaust fans for the emergency diesel generators, containment spray isolation valves, and high pressure safety injection isolation valves. Using NRC Inspection Manual Chapter 0609, Appendix A, The Significance Determination Process (SDP) for Findings At-Power, the inspectors determined to require a detailed risk evaluation because the finding involved degradation of equipment specifically designed to mitigate a seismic event and could degrade one train of a system that supports a risk significant function. A senior reactor analyst performed the detailed risk evaluation and estimated the change to the core damage frequency was 3.8E-8/year (Green). The dominant core damage sequences included seismically induced losses of offsite power. This finding did not have a cross-cutting aspect associated with it because the most significant contributing cause was not indicative of present performance. Specifically, the condition had existed since plant construction, with no recent substantial opportunities to identify the issue.
05000456/FIN-2015002-02Braidwood2015Q2Mechanic Joint Leakage Accepted for Continued Service Without Code Corrective ActionsThe inspectors identified a finding of very low safety significance and an associated NCV of 10 CFR Part 50, Appendix B, Criterion V, Instructions, Procedures and Drawings, for the licensees failure to follow a procedure for completing an American Society of Mechanical Engineers (ASME) Section XI Code pressure test. Specifically, the licensee failed to implement the required corrective actions or evaluations for evidence of leakage (boric acid deposits) identified on a containment spray (CS) system valve bolted connection prior to returning this component to service. The licensee entered this issue into their CAP and initiated actions to clarify procedures to ensure the ASME Code Section XI, Paragraph IWB-3522, requirements were implemented, and components with Code relevant conditions were corrected or evaluated prior to returning them to service. The performance deficiency was determined to be more than minor in accordance with IMC 0612, because if left uncorrected, the performance deficiency would have the potential to lead to a more significant safety concern. Specifically, the failure to adhere to procedure ER AA-330-001 was based upon the licensees decision to return a component exhibiting evidence of boric acid leakage to service without Code corrective measures or evaluation. Additionally, this type of error could result in inservice failure of equipment. Therefore, this finding affected the Mitigating Systems Cornerstone attribute of Equipment Performance and adversely affected the Cornerstone objective of ensuring the availability, reliability and capability of systems that respond to initiating events to prevent undesirable consequences (i.e. core damage). The finding screened as having very low safety significance (Green), because the licensees failure to adhere to procedure ER AA-330-001 and remove valve 1CS011B from service with a Code relevant condition did not result in operation of the plant with an inoperable system or component. Therefore, the inspectors answered Yes to Question A.1 of Exhibit 2, Mitigating Systems Screening Questions, identified in Appendix A of IMC 0609, and the finding screened as having very low safety significance. The inspectors identified a cross-cutting aspect associated with this finding in the area of Human Performance, Conservative Bias because the licensee staff did not use a decision-making practice that emphasized prudent choices over those that were simply allowable. Specifically, the failure to remove valve 1CS011B from service with a relevant condition was based upon the licensees decision that this was an allowable option because the ASME Code Section XI paragraph was not clear. (H14)
05000390/FIN-2015002-04Watts Bar2015Q2Failure to Follow Procedure during SSPS TestingA self-revealing, Non-Cited Violation (NCV) of 10 CFR Part 50, Appendix B, Criterion V, Instructions, Procedures, and Drawings was identified for the licensees failure to follow procedure 1-SI-99-10-A, 62 Day Functional Test of Solid State Protection System (SSPS) Train A and Reactor Trip Breaker A, Revision 59 as amended, for troubleshooting by Procedure Control Form 070-4. Specifically, the licensee attempted to take voltage measurements which were not directed by the revised procedure. The licensee stopped testing, conducted a prompt investigation and removed the first line supervisor and foreman from their duties pending remediation. The licensee placed the issue into their corrective action program as CR 1015778 The performance was more than minor because it adversely affected the equipment performance attribute of the mitigating systems cornerstone to ensure the availability of systems that respond to initiating events to prevent undesirable consequences (i.e., core damage). Specifically, the failure to follow the troubleshooting procedure resulted in drawing an arc in the SSPS cabinet and tripping an upstream supply breaker which resulted in the inoperability of the 1A-A containment spray pump. The inspectors determined that this finding was of very low safety significance (Green) because the finding did not represent an actual loss of function of a single train of containment spray for greater than its Tech Spec allowed outage time. The performance deficiency had a cross-cutting aspect of Procedure Adherence in the area of Human Performance because crew members failed to follow the work instructions in the troubleshooting procedure (H8).
05000315/FIN-2015001-01Cook2015Q1Inadequate Acceptance Criteria for Containment Spray Heat Exchanger InspectionsThe inspectors identified a finding of very-low safety significance, and associated NCV of 10 CFR Part 50, Appendix B, Criterion V, Instructions, Procedures, and Drawings, for the failure to follow the containment spray (CS) heat exchanger inspection procedure. Specifically, the licensee did not develop acceptance criteria applicable for the visual inspection of these heat exchangers. The licensee entered this finding into their CAP to evaluate and resolve, including developing applicable visual inspection acceptance criteria for the CS heat exchangers. The performance deficiency was determined to be more than minor because it was associated with the Barrier Integrity cornerstone attribute of structures, systems, components (SSCS), and barrier performance, and adversely affected the cornerstone objective of providing reasonable assurance that physical design barriers (fuel cladding, reactor coolant system, and containment) can protect the public from radionuclide releases caused by accidents or events. The finding screened as very-low safety significance (Green) because it did not represent an actual open pathway in the physical integrity of reactor containment, containment isolation system, or heat removal components, and did not involve an actual reduction in function of hydrogen igniters in the reactor containment. The inspectors determined this finding had an associated cross-cutting aspect in the area of Human Performance because the licensee did not stop when faced with uncertain conditions. Specifically, the licensee did not develop shell-side visual inspection acceptance criteria because they did not challenge the applicability of the guidance contained in their procedures. (H.11)
05000317/FIN-2015001-01Calvert Cliffs2015Q1Component Cooling Operated in Unanalyzed ConditionThe inspectors identified a Green NCV of Technical Specification (TS) Limiting Condition for Operation (LCO) 3.7.5, Component Cooling (CC) System, and 3.0.3, because Exelon operated Units 1 and 2 CC systems in an unanalyzed condition on 18 occasions and operated in a condition prohibited by TS on two occasions within the last three years. The inspectors determined that Exelons operation with both CC loops inoperable and the subsequent failure to place the unit in Mode 5 within 37 hours as required by TS is a performance deficiency. Exelon entered this issue into their corrective action program (CAP) as IR02439913. Exelons immediate corrective actions included the submission of event notification (EN) 50752 and prohibiting operation of the CC system in a configuration outside of that specified in the TS bases while further analysis was conducted. The inspectors reviewed IMC 0612, Appendix B, Issue Screening, and determined the issue is more than minor because it is associated with the configuration control attribute of the Mitigating Systems cornerstone and adversely affected the cornerstone objective to ensure the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences. Specifically, the station operated with two CC loops unable to perform their safety function of maintaining component cooling heat exchanger (CCHX) outlet temperatures at or below 120F. In accordance with IMC 0609, Attachment 4, Initial Characterization of Findings, issued on June 19, 2012, and IMC 0609, Appendix A, The Significance Determination Process (SDP) for Findings At-Power, Exhibit 2, Mitigating Systems Screening Questions, issued on June 19, 2012, the inspectors determined that a detailed risk evaluation was necessary to disposition the significance of this finding because the finding represented a loss of a system and/or function. The detailed risk evaluation considered that the deficiency could have, under some ultimate heat sink temperature conditions, resulted in the CCHX outlet temperatures exceeding the design analyzed limit of 120F following the recirculation actuation signal (RAS) during a loss of coolant accident (LOCA). The Senior Reactor Analyst performed a bounding significance determination by conservatively assuming a complete loss of safety function for the CCHXs for the applicable limited exposure time. Emergency operating procedures also had contingencies for a postulated loss of the CC function which directed the re-alignment of a containment spray (CS) pump to ensure adequate safety injection is maintained. This evaluation determined the issue was of very low safety significance (Green). The inspectors determined that the finding has a cross-cutting aspect in the area of Human Performance, Design Margins, because Exelon did not operate and maintain equipment within design margins. Specifically, Exelon operated the CC system outside its design safety-related specification, resulting in an operating condition prohibited by TS.
05000425/FIN-2015001-02Vogtle2015Q1Failure to Implement Maintenance Procedure for Containment Spray PumpA self-revealing NCV of TS 5.4.1.a, Procedures, was identified for the licensees failure to verify that the total indicated run-out (TIR) for the Unit 2 B train containment spray pump was within the limits of procedure 27052-C, Gould 3415 Pump Maintenance Procedure, Ver. 6.0. This violation was entered into the licensees corrective action program as CR 855892. The failure to implement maintenance procedure 27052-C was a performance deficiency. The performance deficiency was more than minor because it was associated with the SSC and Barrier Performance attribute of the Barrier Integrity cornerstone and adversely affected the cornerstone objective in that the failure to verify the 2B CS pump shaft TIR was within the procedural and vendor recommendation limits affected the CS system availability and reliability. The finding to be of very low safety significance (Green) because the finding did not represent an actual open pathway in the physical integrity of reactor containment, containment isolation system, or heat removal components, and it did not involve a reduction in function of hydrogen igniters in the reactor containment. No cross-cutting aspect was assigned to this finding because the inspectors determined that the cause of the finding was not indicative of current licensee performance.
05000255/FIN-2014008-12Palisades2014Q4Component Cooling Water System Licensing BasesThe inspectors identified an Unresolved Item (URI) regarding the licensing bases for the Component Cooling Water (CCW) system. Specifically, the inspectors require clarification as to what failures of the CCW system the licensee needs to postulate and evaluate. The NRC will conduct further inspection to determine when these changes to the licensing bases occurred. As part of the 2014 Component Design Bases Inspection (CDBI), the inspectors selected CCW pump P-52B and relief valve RV-0956 for review. Both of these components were part of the CCW system. The CCW system was designed as a closed cycle system, where both trains share a common suction and common discharge header. This means that although there were redundant pumps and heat exchangers, the system's piping was not designed to be redundant and a single pipe break or failure of the pressure boundary could result in the complete loss of CCW. One of CCW's safety functions was to transfer heat from the reactor and containment (post-Design Bases Events/Accidents) to the ultimate heat sink. Another important safety function for CCW was to provide cooling to the Engineered Safeguard Systems' (ESS) and containment spray (CS) pumps. Per the licensees design bases, cooling to the ESS pumps was required to maintain their operability. When reviewing the licensing bases for the plant, it was not clear what type of failures needed to postulated for the CCW system under post-accident conditions. The licensee's position was postulating a passive failure of CCW concurrent with a design bases accident (DBA) was not within their licensing bases. The licensee's position was that no active single failure, according to their definition in FSAR Section 1.4.16, would render CCW inoperable. They also considered a postulated failure of the non-safetyrelated portion of the CCW system inside containment as beyond design bases, except as result of a seismic event which was not postulated to occur in conjunction with an accident. Currently, the licensee credits post-accident heat being removed from containment by a combination of containment air coolers (CAC) and the containment spray (CS) system. The CAC are supplied by service water and are independent of the CCW system. Per the current design, the licensee needs either two CS pumps or one CS pump and three CACs. Both alternatives require the CCW system to remove heat from the CS system. However, the original design took credit for the CS and the CAC as independent and redundant in their capability to remove heat from the containment. In other words, originally the licensee needed either two CS pumps or three CACs. Additionally, the original design allowed for the capability to swap cooling water to the ESS pumps from CCW to service water remotely from the main control room (MCR). Both of these design flexibilities have been either lost or eliminated due to subsequent design changes. The inspectors noted the agency staff had previously evaluated the susceptibility of CCW to loss of function following certain assumed CCW pipe breaks during the Systematic Evaluation Program(SEP). This was documented on SEP Topic IX-3, Station Service and Cooling Water Systems Palisades, February 22, 1982. The agency staff had concluded the CCW design was not in conformance with GDC 44, regarding capability and redundancy of essential functions of the system. However, the staff noted the essential functions of CCW could be performed by other systems under all operating conditions. The SEP evaluation explicitly addressed a passive failure of the CCW system under post-accident conditions and concluded that the CACs would be capable of removing heat from containment. The inspectors were concerned that if the CCW system became inoperable as the result of non-safety-related component failures, the plant would no longer have the redundant capability to remove heat from the containment during a DBA, or provide alternate cooling to the ESS pumps from the MCR. In addition, the inspectors needed to clarify the licensing bases regarding a postulated loss of CCW concurrent with a design bases accident. This issue is unresolved pending further inspection to determine when these changes to the licensing bases occurred.
05000255/FIN-2014008-05Palisades2014Q4Failure to Perform Comprehensive Pump Testing of Containment Spray Pump P-54A in accordance with the Inservice Testing ProgramThe inspectors identified a finding of very low safety significance and associated Non-Cited Violation of Technical Specifications 5.5.7, "Inservice Testing Program," for the failure to perform comprehensive pump testing of Containment Spray Pump P-54A in accordance with the code of record. Specifically, the licensee did not rerun a comprehensive pump test, as required by the codes ISTB-6300 Systematic Error section. As part of their corrective actions, the licensee entered the issue into the Corrective Action Program, and determined the component remained operable. The performance deficiency was determined to be more than minor because it impacted the Equipment Performance attribute of the Reactor Safety, Mitigating Systems Cornerstone and adversely affected the cornerstone objective to ensure the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences. Specifically, failing to perform testing as required could result in the degradation of the equipment being undetected. The finding screened as having very low safety significance because the finding was a deficiency affecting the design or qualification of a mitigating structure system or component (SSC) but the SSC maintained its operability. The findings had a cross-cutting aspect in the area of Problem Identification and Resolution, Evaluation, because the licensee failed to thoroughly evaluate the issue to ensure that resolutions address causes and extents of conditions commensurate with their safety significance.
05000336/FIN-2014004-01Millstone2014Q3Licensee-Identified ViolationTS 3.6.2.1, Containment Spray and Cooling Systems, requires two containment spray trains and two containment cooling trains to be operable in Modes 1, 2, and 3. If one containment spray train is inoperable, the TS required action is to restore the inoperable train within 72 hours or be in Hot Standby within 6 hours. Contrary to the above, at 7:33 PM on May 16, Dominion exceeded the 72 hour allowed outage time for the A containment spray train, due to the delayed completion of the gas void detection surveillance test. In addition, TS 3.0.4 prohibits entry into an Operational Mode without all requisite limiting conditions of operation met. Contrary to the above, at 7:33 PM on May 13, Unit 2 entered Mode 3 with pressure greater than 1750 psia and an inoperable A containment spray train. Dominion entered the issue into the CAP as CR 549280. The inspectors determined that this finding was of very low safety significance using IMC 0609, Appendix A, because the period of unavailability was of short duration (approximately 88 hours) and occurred during Mode 3. The B train of containment spray remained unaffected by the voids found in the A train.
05000285/FIN-2014004-02Fort Calhoun2014Q3Failure to Maintain a Testing Program for the Containment Spray SystemThe inspectors identified a Green non-cited violation of 10 CFR Part 50, Appendix B, Criterion XI, Test Control, because the licensee failed to ensure that a surveillance test program was sufficient to demonstrate that the containment spray (CS) system would perform satisfactorily in service. Specifically, from February, 2014, to September, 2014, the licensee failed on several occasions to adequately adjust the frequency of testing for gas voids in the CS system upon identification of gas voids beyond acceptance criteria. Consequently, the test monitoring frequency did not ensure operability of the CS system between tests. Subsequently, the licensee increased the CS monitoring frequency. The performance deficiency is more than minor because it is associated with the Equipment Performance attribute of the Mitigating Systems cornerstone and adversely affected the cornerstone objective to ensure the reliability of systems that respond to initiating events to prevent undesirable consequences. The inspectors performed an initial screening of the finding in accordance with NRC Manual Chapter IMC 0609, Appendix A, The Significance Determination Process (SDP) for Findings At-Power. Using IMC 0609, Appendix A, Exhibit 2, Mitigating Systems Screening Questions, dated July 1, 2012, this finding is of very low safety significance (Green) because it: (1) was not a deficiency affecting the design or qualification of a mitigating system; (2) did not represent a loss of system and/or function; (3) did not represent an actual loss of function of a single train for greater than its technical specification allowed outage time; and (4) does not represent an actual loss of function of one or more non-technical specification trains of equipment designated as high safety-significant for greater than 24 hours in accordance with the licensees maintenance rule program. The finding has a cross-cutting aspect in the Problem Identification and Resolution area and the Trending aspect because the licensee failed to trend and analyze information from the corrective action program and other assessments in the aggregate to identify programmatic and common cause issues.
05000425/FIN-2014004-05Vogtle2014Q3NOED 14-2-03 to allow mechanical seal replacement and testing of the Unit 2 B Containment Spray PumpThe inspectors identified an unresolved item (URI) regarding NOED 14-2-03 granted on August 21, 2014. The inspectors reviewed NOED 14-2-03 and related documents to determine the accuracy and consistency with the licensees assertions and implementation compensatory measures and commitments, those of which included ensuring the availability of both trains of the emergency core cooling systems, both trains of the containment cooler units, and the remaining train of the CS system. Additional inspection is required to conduct a review of the licensee event report (LER) and licensee root cause analysis to determine if the 2B CS pump inboard mechanical seal failure was associated with a performance deficiency and violation of NRC requirements. This URI is identified as URI 05000425/2014004-05 NOED 14-2-03 to allow mechanical seal replacement and testing of the Unit 2 B Containment Spray Pump.
05000275/FIN-2014007-03Diablo Canyon2014Q3Longstanding Uncompensated Nonconforming ConditionThe team identified a Green non-cited violation of 10 CFR Part 50 Appendix B Criterion XVI for the licensees failure to take timely corrective actions. In 2011, the licensee identified a potential path for gas intrusion into the containment spray system, contrary t design basis requirements. The licensee took no interim or compensatory actions whil planning its final corrective actions. The licensee documented this condition in its corrective action program as SAPN 50657636. The failure to take timely corrective actions as required by 10 CFR 50 Appendix B Criterion XVI was a performance deficiency. This performance deficiency was more than minor because it was associated with the design control 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. Using Inspection Manual Chapter 0609 Appendix A, the team determined that this finding was of very low safety significance (Green) because it did not result in the loss of operability or functionality of a system or train. This finding has a conservative bias cross-cutting aspect in the human performance cross-cutting area because licensee personnel failed to use decision-making practices that emphasized prudent choices over those that were simply allowable (H.14). Specifically, licensee managers failed to take timely action to address degraded conditions commensurate with their safety significance.
05000266/FIN-2014004-03Point Beach2014Q3Deficiencies in Calculation Performed to Support Containment Dome Truss OperabilityThe inspectors identified a finding of very low safety significance for deficiencies in licensees calculation performed to support operability of the unit 1 containment building dome truss and the safety related components supported from the truss. The licensee reassessed the dome truss members and connections that were found to be highly stressed and concluded that the components remained within the acceptable limits. The licensee initiated action request (AR) 01986069 to capture the concern identified by the inspectors and revised the POD. The finding was determined to be more than minor because the finding is associated with the reactor coolant system (RCS) Equipment and Barrier Performance Attribute of the Barrier Integrity cornerstone and adversely affected the cornerstone objective of providing reasonable assurance that physical design barriers (fuel cladding, reactor coolant system, and containment) protect the public from radionuclide releases caused by accidents or events. Specifically, failure of the dome truss could impact the reliability/availability of the containment spray system to maintain operability of the containment. Additionally, More than Minor Example 3.j of IMC 0612, Appendix E, Examples of Minor Issues, was used to inform the answer to this more than minor screening question. Specifically, the licensees failure to address torsional effects and use of non-conservative allowable stress values for evaluation of containment dome truss components, at the time of discovery, resulted in reasonable doubt of the operability of the subject walls. In accordance with IMC 0609, Significance Determination Process, Attachment 4, Initial Characterization of Findings, Table 2, the inspectors determined the finding affected the Barrier Integrity cornerstone. As a result, the inspectors determined the finding could be evaluated using IMC 0609, Appendix A, The Significance Determination Process (SDP) for Findings At-Power, Exhibit 3. Because the finding did not represent an actual failure of a component required to maintain containment integrity, the inspectors answered No to Screening Questions 1 and 2 for the Reactor Containment section, and determined the finding was of very low safety significance. This finding has a cross-cutting aspect of Conservative Bias (H.14) in the area of human performance for the licensees failure to use conservative decision making practices in the operability evaluation of the containment dome truss.
05000282/FIN-2014004-04Prairie Island2014Q3Licensee-Identified ViolationTitle 10 CFR 20.1601 requires control for access to high radiation areas (HRAs) and subpart (c) allows a licensee to apply to the NRC for approval of alternative methods for controlling HRA access. At Prairie Island Nuclear Generating Plant, the NRC-approved alternate methods for controlling access to HRAs include station TS 5.7. Specifically, TS 5.7.1.b for HRA access requires, in part, that Access to, and activities in each such area shall be controlled by means of a Radiation Work Permit (RWP)... Additionally, TS 5.7.1.e for HRA access requires, in part, that ...entry into such areas shall be made only after dose rates in the area have been determined and entry personnel are knowledgeable of them. Contrary to the above, on October 26, 2013, a worker willfully entered a posted and barricaded HRA inside the Unit-2 containment spray pump room on a RWP that did not authorize HRA entry and without being knowledgeable of the radiological conditions prior to entry. Corrective actions for this issue included performance management of the individuals involved in accordance with station management protocols. Because this violation was Severity Level IV, and it was entered into the licensees CAP as CAP 1403583, this violation is being treated as a NCV consistent with Section 2.3.2 of the NRC Enforcement Policy.
05000483/FIN-2014003-01Callaway2014Q2Plastic Shipping Plug in Rosemount TransmitterThe inspectors identified a finding for the licensees failure to properly install a flow transmitter for the containment spray system. Specifically, since construction, Rosemount Transmitter ENFT0005, which provides a signal for containment spray train A pump flow rate, had a plastic shipping plug installed in the spare conduit port instead of the vendorrequired stainless steel plug. The licensee did not include this transmitter as part of an operating experience extent of condition walkdown conducted in 2010 because the transmitter provides indication only and does not have an active safety function. However, the inspector determined that this transmitter provides operator post-accident monitoring capability of containment spray pump performance. The licensee entered this issue into the corrective action program as Callaway Action Request 201403300. The licensee reviewed this deficiency and determined that although Transmitter ENFT0005 was degraded, the containment spray system remained operable. The licensee promptly replaced the plastic shipping plug with the required stainless steel plug. Failure to properly install a Rosemount transmitter needed for post-accident monitoring to its qualified configuration was a performance deficiency. This performance deficiency was more than minor, and therefore a finding, because it adversely affected the configuratio control attribute and the Barrier Integrity Cornerstone objective to provide reasonabl assurance that physical design barriers (i.e., containment) protect the public fro radionuclide releases caused by accidents or events. Specifically, the improperly configured containment spray flow transmitter could have resulted in erratic spray flow indication, which could impede operators ability to monitor this parameter and act upon the indication. The finding is of very low safety significance (Green) because containment spray is not a significant contributor to large early release frequency. This finding does not have a cross-cutting aspect because the transmitter was installed in this manner during original construction and, thus, was not indicative of current licensee performance.
05000348/FIN-2014007-08Farley2014Q2Failure to Update the FSAR with the Safety Analysis Performed in Response to GL 2008-01The team identified a Severity Level (SL) IV non-cited violation of 10 CFR 50.71, Maintenance of Records, Making of Reports, for the licensees failure to update the Updated Final Safety Analysis Report (UFSAR). Specifically, the UFSAR was not updated to reflect the analysis requested by the NRC in GL 2008-01, Managing Gas Accumulation in Emergency Core Cooling, Decay Heat Removal, and Containment Spray Systems. The licensee entered the issue into the corrective action program as condition report 823270. The team determined the failure to update the UFSAR with the analyses performed for GL 2008-01 was a performance deficiency. Failures to update the UFSAR are dispositioned using the traditional enforcement process instead of the SDP in accordance with IMC 0612, Appendix B, Block TE2, because they potentially impede or impact the regulatory process. Specifically, failures to update the UFSAR challenges the regulatory process because it serves as a reference document used, in part, for recurring safety analyses, evaluating license amendment requests, and in preparation for and conduct of inspection activities. As a result, the team compared the performance deficiency against the examples in Section 6.1 of the NRC Enforcement Policy and determined it constituted a more than minor traditional enforcement violation because it rose to a SL-IV violation. Specifically, SL-IV violation example d.3 stated A licensee fails to update the UFSAR as required by 10 CFR 50.71(e) but the lack of up-to-date information has not resulted in any unacceptable change to the facility or procedures. The team determined an evaluation for cross-cutting aspect was not applicable because this was a traditional enforcement violation.
05000285/FIN-2014002-08Fort Calhoun2014Q1Failure to Adequately Design Anchorage for Containment Spray and Raw Water System Pipe SupportsDuring a previous inspection, the NRC reviewed multiple calculations for pipe supports on the raw water and containment spray systems and found that the calculations had several errors related to the design requirements for anchorage. The NRC issued an apparent violation AV 05000285/2013012-08, Failure to adequately design anchorage for containment spray and raw water system pipe supports in NRC Inspection Report 05000285/2013-012 (ML 13144A772). The licensee performed an operability determination for the affected calculations and found that the anchorage for the raw water and containment spray piping supports were operable. The NRC reviewed the evaluations and concluded that reasonable assurance of operability existed for the affected components. The inspectors determined that the failure to ensure adequacy of the anchorage of the aforementioned Containment Spray Pipe Supports and Raw Water Pipe Supports was not in accordance with design basis requirements and was a performance deficiency. The performance deficiency was determined to be more than minor because it required calculations to be re-performed to prove the system was operable, and it was associated with the Mitigating Systems cornerstone attribute of design control and affected the cornerstone objective of ensuring the availability, reliability, and capability of the containment spray system and raw water system. Using Inspection Manual Chapter 0609, Attachment 4 Initial Characterization of Findings, and Appendix A The Significance Determination Process (SDP) for findings at-power, both dated 6/19/12, the inspectors determined the performance deficiency affected the mitigating systems cornerstone and screened to Green because the finding affected the design and qualification of a mitigating SSC but remained operable. The inspectors used the at-power SDP because the condition existed since construction and while the plant was predominantly at power. The inspectors determined there was no cross-cutting aspect associated with this finding because the calculations were from the 1980s and therefore were not reflective of current performance. Title 10 CFR Part 50, Appendix B, Criterion III, Design Control states, in part, that the design control measures shall provide for verifying or checking the adequacy of design, such as by the performance of design reviews, by the use of alternate or simplified calculational methods, or by the performance of a suitable testing program. Contrary to this requirement the inspectors identified that calculations FC00607, FC01785, FC01786, FC01791, FC01864, FC01691, FC01902, FC02409, FC02412, FC04228, FC02433, FC02436, and FC02425 for the raw water and containment spray systems failed to ensure adequacy of the design. Specifically, these anchorage calculations did not conform to applicable design requirements from approximately 1980 until June 2013. The licensee entered these issues into the corrective action program as CR 2013-05304 and performed an operability determination as immediate actions. Long term actions to resolve the errors in the calculations are also implemented by the referenced CR. This violation is being treated as an NCV, consistent with Section 2.3.2.a of the Enforcement Policy.
05000382/FIN-2014002-04Waterford2014Q1Failure to Establish Adequate Design Control Measures for the Selection and Review for the Suitability of Application of Molded Case Circuit BreakersA self-revealing, non-cited violation of 10 CFR Part 50, Appendix B, Criterion III, Design Control, occurred because the licensee did not establish design control measures for the selection and review for the suitability of application of a molded case circuit breaker that was essential to the safety-related function of a shutdown cooling heat exchanger fan cooler. Specifically, the licensee did not select and review for the suitability of the correct safety-related circuit breaker for the application to provide circuit fault protection to the train B shutdown cooling heat exchanger air handling unit fan motor. The licensee entered this condition into their corrective action program as Condition Reports CR-WF3-2013-02316 and CR-WF3-2013-04644. The immediate corrective action taken to restore compliance included the replacement of the breaker with a breaker more suitable for the application to protect the air handling unit fan motor. The planned corrective actions included an extent of condition review for other installed breakers and the revision of work order instructions to eliminate the practice of substituting and using the factory acceptance testing for pre-installation and post-maintenance tests, respectively. The inspectors concluded that the failure to establish design control measures for the selection and review for suitability of application for the correct safety-related circuit breaker was a performance deficiency. The performance deficiency was more than minor because it was associated with the design control attribute of the mitigating systems cornerstone and adversely affected the cornerstone objective to ensure the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences. Specifically, the incorrect breaker affected the availability, reliability, and capability of the shutdown cooling heat exchanger fan coolers to remove heat from the shutdown cooling heat exchanger areas following a design basis accident. The inspectors performed the initial significance determination. The inspectors used the NRC Inspection Manual 0609, Attachment 4, Initial Screening and Characterization of Findings. The initial screening directed the inspectors to use Inspection Manual Chapter 0609, Appendix A, The Significance Determination Process (SDP) for Findings At-Power, Exhibit 2, Section A, to determine the significance of the finding. The finding required a detailed risk evaluation because it involved a potential loss of one train of safety-related equipment for longer than the technical specification allowed outage time. The total exposure period was 23 days. The allowed outage time was 7 days. A Region IV senior reactor analyst performed the detailed risk evaluation and determined that the change to the core damage frequency was 5E-13/year (Green). The dominant core damage sequences included loss of offsite power events, failure of both trains of containment spray, and the failure of a pressurizer safety relief valve to remain closed. The equipment that helped mitigate the risk included the emergency diesel generators and the essential feedwater systems. The inspectors concluded that the finding reflected current licensee performance and involved a cross-cutting aspect of avoiding complacency in the human performance area because the licensee did not recognize and plan for the possibility of mistakes, latent issues, and inherent risk on relying on 21 year old vendor information and installing a breaker without pre-installation and adequate post-maintenance testing.
05000285/FIN-2014002-07Fort Calhoun2014Q1Inadequate 10 CFR 50.59 Screening for Containment Spray Design ChangeA cited violation of 10 CFR 50, Appendix B, Criterion XVI, Corrective Action, was identified involving the failure to take timely corrective action for a condition adverse to quality. Specifically, the licensee failed to restore compliance following NRC identification of the licensees failure to correct a runout condition of the containment spray system (CS) documented in NCV 05000285/2008003-05, in August 2008. Licensee corrective actions to correct the issue included completion of an analysis of containment spray pump operation during the main steam line break (MSLB) event; revision of CS design documentation; analysis of motor performance by an electrical vendor; and completion of a temporary modification to throttle the CS pump discharge valves to provide additional system resistance preventing pump runout. Future corrective actions include a permanent design change to prevent CS pump runout. The licensee initiated CR 2014-02242 on February 19, 2014, to document this failure to restore compliance. This finding was more than minor because it adversely impacted the Barrier Integrity cornerstone objective to provide reasonable assurance that physical design barriers (containment) protect the public from radionuclide releases caused by accidents or events. The inspectors reviewed NRC IMC 0609, Attachment 4, Initial Characterization of Findings , Table 3 SDP Appendix Router. While this issue was identified during a refueling outage, the inspectors determined that the majority of the exposure time for this violation occurred with the reactor at power and should be evaluated using the Significance Determination Process in accordance with IMC 0609, The Significance Determination Process (SDP) for Findings at- Power, Appendix A, Exhibit 3, Barrier Integrity Screening Questions. The inspectors determined that the finding did not represent an actual open pathway in containment or containment isolation logic, nor did the finding represent an actual reduction in the function of containment hydrogen igniters. Based on the guidance in the Exhibit 3 checklist the inspectors determined that the finding was of very low safety significance. The inspectors determined that the finding had a cross-cutting aspect of avoiding complacency in the human performance area, because the licensees staff failed to recognize latent issues even while expecting successful outcomes.
05000285/FIN-2014002-06Fort Calhoun2014Q1Failure to Restore Compliance for Containment Spray Runout ConditionsA cited violation of 10 CFR 50, Appendix B, Criterion XVI, Corrective Action, was identified involving the failure to take timely corrective action for a condition adverse to quality. Specifically, the licensee failed to restore compliance following NRC identification of the licensees failure to correct a runout condition of the containment spray system (CS) documented in NCV 05000285/2008003-05, in August 2008. Licensee corrective actions to correct the issue included completion of an analysis of containment spray pump operation during the main steam line break (MSLB) event; revision of CS design documentation; analysis of motor performance by an electrical vendor; and completion of a temporary modification to throttle the CS pump discharge valves to provide additional system resistance preventing pump runout. Future corrective actions include a permanent design change to prevent CS pump runout. The licensee initiated CR 2014-02242 on February 19, 2014, to document this failure to restore compliance. This finding was more than minor because it adversely impacted the Barrier Integrity cornerstone objective to provide reasonable assurance that physical design barriers (containment) protect the public from radionuclide releases caused by accidents or events. The inspectors reviewed NRC IMC 0609, Attachment 4, Initial Characterization of Findings , Table 3 SDP Appendix Router. While this issue was identified during a refueling outage, the inspectors determined that the majority of the exposure time for this violation occurred with the reactor at power and should be evaluated using the Significance Determination Process in accordance with IMC 0609, The Significance Determination Process (SDP) for Findings at- Power, Appendix A, Exhibit 3, Barrier Integrity Screening Questions. The inspectors determined that the finding did not represent an actual open pathway in containment or containment isolation logic, nor did the finding represent an actual reduction in the function of containment hydrogen igniters. Based on the guidance in the Exhibit 3 checklist the inspectors determined that the finding was of very low safety significance. The inspectors determined that the finding had a cross-cutting aspect of avoiding complacency in the human performance area, because the licensees staff failed to recognize latent issues even while expecting successful outcomes.
05000528/FIN-2014007-01Palo Verde2014Q1Failure To Provide Adequate Technical Justification For Operability of Containment Spray and Diesel Fuel Oil SystemsThe inspectors identified multiple examples of a Green non-cited violation of 10 CFR Part 50, Appendix B, Criterion V, Instructions, Procedures, and Drawings, for the failure of operations personnel to follow station procedures used to perform operability determinations. Specifically, operations personnel failed to provide sufficient technical justification for the reasonable assurance of operability of a degraded condition involving one train of containment spray system and nonconforming conditions associated with diesel fuel oil piping. The inspectors concluded the failure of operations personnel to follow station procedures to perform operability determinations was a performance deficiency. The performance deficiency was more than minor, and therefore a finding, because it adversely affected the equipment performance attribute of the Mitigating Systems Cornerstone and affected the cornerstone objective of ensuring the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences. The inspectors evaluated the significance of the issue under the Significance Determination Process, as defined in Inspection Manual Chapter 0609.04, Initial Characterization of Findings, and 0609, Appendix A, The Significance Determination Process (SDP) for Findings at-Power. The inspectors concluded the finding was of very low safety significance (Green) because all questions in Exhibit 2 could be answered in the negative. The inspectors determined that the finding had a consistent process cross-cutting aspect in the area of human performance because the licensee did not use a consistent and systematic process to make decisions (H.13).
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