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05000498/FIN-2018002-012018Q2South TexasLicensee-Identified ViolationThis violation of very low safety significance was identified by the licensee, has been entered into the licensees corrective action program and is being treated as a Non-Cited Violation, consistent with Section 2.3.2 of the Enforcement Policy. Violation: Technical Specification 6.8.1.a requires that, Written procedures shall be established, implemented, and maintained covering the activities referenced below: The applicable procedures recommended in Appendix A of Regulatory Guide 1.33, Revision 2, February 1978. Section 9.a, Procedures for Performing Maintenance, states, in part, that Maintenance that can affect the performance of safety-related equipment should be properly preplanned and performed in accordance with written procedures, documented instructions, or drawings appropriate to the circumstances. The licensee established Procedure COM-0001, Conduct of Maintenance, to guide maintenance craft on what to do if a condition or issue arises during a maintenance activity. Specifically, Section 1.4 Supervisor Responsibilities, states, in part, that, If we cannot find the problem with the component or piece of equipment, the issue must be raised to the Division Manager/General Supervisor BEFORE we close the work control document AND return the equipment to operations. Contrary to the above, on March 10, 2017, Unit 1 E1B undervoltage relay was found outside the technical specification acceptance criteria, and was retested until the relay it was back in tolerance and placed back into service (declared operable) instead of raising the issue up to the division manager for further evaluation. The issue was discussed with the electrical maintenance supervisor and the findings were documented in Condition Report 17-12616. The relay was declared operable and placed back into service. Subsequently, after review of the condition report, approximately 99 hours after the relay was declared inoperable, the relay was replaced, and the system declared operable. Significance/Severity Level: The inspectors determined the performance deficiency was more than minor because it adversely affected the equipment performance attribute of the Mitigating Systems 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 undervoltage relay was outside its tolerance and placed back into service without correcting the cause of being outside its tolerance. The inspectors assessed the significance of the finding using Exhibit 2, Mitigating Systems Screening Questions, of Inspection Manual Chapter 0609, Appendix A, Significance Determination Process (SDP) for Findings At-Power, issued June 19, 2012, and determined this finding is not a deficiency affecting the design or qualification of a mitigating structure, system, and component that maintained its operability or functionality; the finding does not represent a loss of system and/or function; the finding does not represent an actual loss of function of at least a single train for greater than its Technical Specification-allowed outage time; and 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. Therefore, the inspectors determined the finding was of very low safety significance (Green). Corrective Action Reference: Condition Report 17-12616
05000382/FIN-2018001-012018Q1WaterfordFailure to Obtain NRC Staff Authorization Prior to Changing a Procedure that Impacts Implementation of Technical SpecificationsThe inspectors identified a Severity Level IV, non-cited violation of 10CFR50.59, Changes, Tests, and Experiments, Section (c)(1), for the licensees failure to submit and obtain authorization prior to implementation procedures described in the Final Safety Analysis Report
05000313/FIN-2017003-012017Q3Arkansas NuclearFailure to Maintain Service Water Train SeparationThe inspectors identified a non- cited violation of Technical Specification 5.4.1.a for the licensees failure to maintain train separation between safety -related service water trains when swapping the swing high pressure injection (HPI) pump between trains. Specifically, by following procedure OP 1104.002, Makeup and Purification System Operation, Revision 89, operators cross -tied service water trains, placing the system in an unanalyzed condition. This condition resulted in the train A electrical equipment room emergency chiller and train B reactor building emergency cooling coils being inoperable for a maximum of 25 minutes per occurrence. Additionally, it was determined that service water temperatures over the past 3 years did not result in an actual loss of function associated with these components if a design basis accident would have occurred. The immediate corrective actions were to assess past operability for not maintaining service water train separation and to revise Operating Procedure 1104.002 with adequate work instructions to maintain service water train separation. The licensee entered this deficiency into the corrective action program as Condition Report CR -ANO -1-2017- 02518. The licensees failure to maintain safety -related service water train separation when swapping the swing HPI pump between trains was a performance deficiency. The performance deficiency was more than minor because it was associated with the procedural quality attribute of the Mitigating Systems Cornerstone, and adversely affected the cornerstone objective to ensure availability, reliability, and capability of systems that respond to initiating events. Specifically, the licensees failure to maintain service water train separation placed the system in an unanalyzed condition and was subsequently determined to cause the train A electrical equipment room emergency chiller and train B reactor building emergency cooling coils to be inoperable for a maximum of 25 minutes per occurrence . Using Inspection Manual Chapter 0609, Appendix A, The Significance Determination Process (SDP) for Finding s At-Power, dated June 19, 2012, the inspectors determined that the finding had very low safety significance (Green) because it: was not a design deficiency; did not represent a loss of system and/or function; did not represent an actual loss of function of at least a single train for longer than its technical specification allowed outage time; and did not result in the loss of a high safety -significant , non -technical specification train. Specifically, inspectors confirmed that service water temperatures were never high enough to result in an actual loss of function for either limiting component. The finding had 3 a cross -cutting aspect in the area of human performance associated with conservative bias because the licensee failed to determine whether the proposed action was safe to proceed, rather than unsafe in order to stop. Specifically, in December 2015 when this approach was revise d to declare only the non- protected service water train inoperable, the licensee did not ensure that the transition lineup was analyzed to be within safety analyses before adopting the revised steps. (H.14)
05000275/FIN-2017002-022017Q2Diablo CanyonFailure to Conduct Required Biennial Medical Examinations Within Two YearsSL -IV. The inspectors identified a Severity Level IV, non -cited violation of 10 CFR 55.21, Medical Examination, for the licensees failure to ensure that a medical examination by a physician to determine satisfaction of 10 CFR 55.33(a)(1) requirements was conducted every 2 years for two licensed senior operators. Specifically, one licensed senior operator exceeded the two- year medical examination requirement by approximately 16 months between November 27, 2015, and April 6, 2017. A second licensed senior operator exceeded the 2 -year medical examination requirement by 4 months between November 19, 2016, and April 6, 2017. As a corrective action, the licensee has conducted the required medical examination for one senior operator and initiated a license termination request for the other senior operator. This issue was entered into the licensees corrective action program as Notification 50912407. The failure of the facility licensee to conduct required biennial medical examinations for two licensed senior operators was a performance deficiency. This issue was evaluated using the traditional enforcement process because it negatively impacted the NRCs ability to perform its regulatory oversight function. Specifically, the failure to comply with medical testing requirements for two operators compromised the facility licensees ability to assure conformance to medical standards, detect non -conforming medical conditions, and report non-conformances to the NRC. This performance deficiency was determined to be Severity Level IV because it fits the Severity Level IV example of Enforcement Policy Section 6.4.d.1, Violation Examples: Licensed Reactor Operators. This section states, Severity Level IV violations involve, for example ... (b) an individual operator who did not meet the American National Standards Institute/American Nuclear Society (ANSI/ANS) 3.4, Medical Certification and Monitoring of Personnel Requiring Operator Licenses for Nuclear Power Plants, Section 5, Health Requirements and Disqualifying Condit ions, as certified on NRC Form 396, Certification of Medical Examination by Facility Licensee, required by 10 CFR 55.23, Certification, but who did not perform the functions of a licensed operator or senior operator while having a disqualifying medical condition. No cross -cutting aspect was assigned because the violation was processed using traditional enforcement.
05000275/FIN-2017002-032017Q2Diablo CanyonFailure to Report a Permanent Medical Condition Within 30 DaysSL -IV. The inspectors identified a Severity Level IV, non -cited violation of 10 CFR 55.25, Incapacitation Because of Disability or Illness, for the licensees failure to notify the NRC within 30 days of a change to one licensed senior operators medical condition. Specifically, the licensed senior operator developed a permanent medical condition which caused him to permanently leave the site on December 1, 2014, and transition into a long- term disability program on April 23, 2015. The licensee did not notify the NRC of this change in medical condition. As a corrective action, the licensee initiated a license termination request for the affected operator, effective April 6, 2017. This issue was entered into the licensees corrective action program as Notification 50912407. The failure of the facility licensee to notify the NRC within 30 days of a change in a licensed senior operators medical condition was a performance deficiency. This issue was evaluated using the traditional enforcement process because it negatively impacted the NRCs ability to perform its regulatory oversight function. Specifically, the failure to report 4 changes in a licensed senior operators medical condition prevented the NRC from taking action to issue either a license amendment or termination, as appropriate. This performance deficiency was determined to be Severity Level IV because it fits the Severity Level IV example of Enforcement Policy Section 6.4.d.1, Violation Examples: Licensed Reactor Operators. This section states, Severity Level IV violations involve, for example (b) an individual operator who did not meet the American National Standards Institute/American Nuclear Society (ANSI/ANS) 3.4, Medical Certification and Monitoring of Personnel Requiring Operator Licenses for Nuclear Power Plants, Section 5, Health Requirements and Disqualifying Conditions, as certified on NRC Form 396, Certification of Medical Examination by Facility Licensee, required by 10 CFR 55.23, Certification, but who did not perform the functions of a licensed operator or senior operator while having a disqualifying medical condition. No cross -cutting aspect was assigned because the violation was processed using traditional enforcement
05000313/FIN-2017002-032017Q2Arkansas NuclearFailure to Comply with ECCS Technical Speci ficationsGreen . The inspectors reviewed a Green self -revealing finding and associated non -cited violation of Unit 1 Technical Specification 3.5.2, Emergency Core Cooling System (ECCS) Operating, for the licensees failure to ensure the operability of the P36A high pressure injection pump after reinstalling its feeder breaker during a unit outage. A violation of Unit 1 Technical Specification 3.0.4 was also identified for making a mode change without meeting the requirements to do so. Following unit restart, the pump failed to start during routine equipment rotation, resulting in one train of emergency core cooling system being inoperable for long er than allowed by Unit 1 Technical Specifications. The licensee subsequently identified that the feeder breaker had not been fully racked into position. Inspectors also noted that the breaker had been racked in manually rather than using the normal electric racking tool, and no special precautions had been taken to ensure this infrequently -used method was successful. When the breaker was correctly racked in, the pump was satisfactorily tested. The licensee subsequently verified that all similar breakers were correctly racked into position. The licensee entered this issue into their corrective action program as Condition Report CR- ANO -1-2017- 01764. The inspectors determined that the failure to verify that the P36A high pressure injection pump was operable after racking its feeder breaker into the switchgear cubicle was a performance deficiency. The performance deficiency was more than minor because it was associated with the human performance 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. 4 The inspectors performed the initial significance determination for the performance deficiency using NRC Inspection Manual 0609, Appendix A, Exhibit 2, Mitigating Systems Screening Questions, dated June 19, 2012 , and concluded that it required a detailed risk evaluation because it involved the loss of a single train of mitigating equipment for longer than the technical specification allowed outage time. Therefore, a Region IV senior reactor analyst performed a bounding detailed risk evaluation. The estimate in the increase in core damage frequency is 4.4 E-8 per year, or of very low safety significance (Green). This finding had a cross-cutting aspect in the area of Human Performance, Avoid Complacency, because the licensee failed to ensure that individuals recognize and plan for the possibility of mistakes, latent issues, and inherent risk, even while expecting successful outcomes. Specifically, the licensee failed to verify that the pump was operable after its breaker was rein stalled, even though an infrequently-used method was employed (H.12).
05000313/FIN-2017002-042017Q2Arkansas NuclearLicensee-Identified ViolationTitle 10 CFR 50.55a(g)4, Inservice Inspection Standards Requirement for Operating Plants, states in part, Throughout the service life of a pressurized water -cooled nuclear power facility, components that are classified as ASME Code Class 1, Class 2, and Class 3 must meet the requirements set forth in Section XI of the ASME Code. The ASME Section XI, Article IWA - 2610, requires that all welds and components subject to a surface or volumetric examination be included in the licensees inservice inspection program. This includes identifying system supports in the inservice inspection plan, per ASME Section XI, Article IWA -1310. Contrary to the above, prior to March 9, 2017, the licensee did not ensure that all welds and components subject to a surface or volumetric examination were included in the licensees inservice inspection. Specifically, the licensee did not apply the applicable inservice inspection requirements for surface or volumetric examination to all portions of the Unit 2 emergency feedwater system within the system ASME Code Class 3 boundary. The licensee identified that they failed to include the emergency feed pump supports in their inservice inspection program. The licensee entered this issue into their corrective action program as Condition Report CR- ANO -2-2016 -01023 and reasonably determined the emergency feedwater system remained operable. The licensee restored compliance by inspecting the supports, with no degradation identified, and entering the emergency feedwater pump supports into the ASME Section XI program. The finding was of very low safety significance (Green) because the finding did not 34 represent an actual loss of safety function of a system or train and did not result in the loss of a single train for greater than technical specification allowed outage time. This issue was entered into the licensees corrective action program as Condition Report CR- ANO -2-2016- 01023.
05000368/FIN-2017002-012017Q2Arkansas NuclearFailure to Follow Fire Protection Program ProceduresGreen . The inspectors identified a finding and associated non -cited violation of License Conditions 2.C.( 3)(b), Fire Protection, for Arkansas Nuclear One Unit 2, associated with the failure to adequately implement the fire protection program. Specifically, the licensee failed to follow the requirements for control of flammable liquid lockers and compressed hydrogen gas cylinders. The licensee immediately removed the hydrogen cylinders and stored them in an approved location and began processing the flammable liquid lockers through the design change process. The licensee entered these issues into their corrective action program as Condition Reports CR -ANO -2-2017- 01525 and CR -ANO -C-2017 -01508 . The failure to properly control transient combustible material in accordance with the approved fire protection program was a performance deficiency. The finding was considered more than minor because storing unanalyzed flammable material could result in the potential to exceed combustible material limits , and is associated with the protection against external factors attribute of the Initiating Events Cornerstone and adversely affected the cornerstone objective to limit the likelihood of events that upset plant stability and challenge critical safety functions during power operations. Specifically, the failure to follow procedures resulted in conditions that increased the risk of fire which could upset plant stability and challenge critical safety functions. The inspectors evaluated the finding using Inspection Manual Chapter 0609, Appendix F, Fire Protection Significance Determination Process, and assigned the finding to the Fire Prevention and Administrative Controls category; because it affected the licensees combustible materials control. The finding was determined to be Green, or very low safety significance, in accordance with Inspection Manual Chapter 0609, Appendix F, Question 1.3.1, because the reactor would have been able to reach and maintain safe shutdown since the postulated fires would not have affected both trains of safe shutdown equipment . This finding had a cross -cutting aspect associated with teamwork within the human performance area since multiple groups in the licensee staff were involved in the decisions that resulted in the improper introduction of the flammable liquids lockers and the improper storage of the hydrogen cylinders (H.4).
05000368/FIN-2017002-022017Q2Arkansas NuclearFailure 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
05000275/FIN-2017002-012017Q2Diablo CanyonInadequate Expansion Scope of Risk - Informed WeldsGreen . The inspectors identified a non -cited violation of the licensees risk -informed inservice inspection program (which is their alternative to portions of the ASME Code, Section XI inservice inspection program approved in accordance with 10 CFR 50.55a(z)) for the failure to properly expand the scope of additional welds to inspect. Specifically, a rejectable flaw on a pipe weld in the pressurizer spray line was identified during refueling outage 1R19 while performing an ultrasonic examination. The licensee expanded the inspection scope by four additional welds, but failed to select those assigned with the same degradation. For immediate corrective actions, the licensee identified and intended to inspect four additional welds assigned to the same degradation mechanism as required by the risk -informed inservice inspection program. This issue was entered into the licensees corrective action program as Notification 50920222. The licensees failure to properly expand the weld examination scope as required by the risk -informed inservice inspection program was a performance deficiency. The performance deficiency was more than minor because it was associated with the equipment performance attribute of the Mitigating System Cornerstone and adversely affected the cornerstone objective of ensuring the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences. Specifically, the failure to select additional welds that were susceptible to the same degradation mechanism as weld WIB -378 placed the plant at an increased risk due to the potential of having an active degradation mechanism that could affect additional components. Using Inspection Manual Chapter 0609, Appendix A, The Significance Determination Process (SDP ) for Findings At-Power, dated June 19, 2012, the inspector s determined the finding screened as having very low significance (Green) because: (1) it was not a design deficiency; (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 technical specification allowed outage time; and (4) did not result in the loss of a high safety -significant non -technical specification train. This finding had a cross -cutting aspect in the area of human performance associated with 3 change management because leaders failed to use a systematic process for evaluating and implementing the change to a risk -informed inservice inspection program. The implementing procedure failed to include the reference to degradation mechanism allowing for a misinterpretation of weld expansion requirements once a flaw was identified in a weld WIB -378 (H.3).
05000275/FIN-2017002-042017Q2Diablo CanyonFailure to Follow Procedures Results in Partial Loss of Cooling Flow to Shutdown CoolingGreen . The inspectors reviewed a self -revealing, non- cited violation of 10 CFR 50, Appendix B, Criterion V, Instructions, Procedures, and Drawings, because PG&E personnel failed to follow the requirements of AD7.ID14, Assessment of Integrated Risk, Revision 11. Specifically, PG&E personnel failed to obtain shift manager permission, conduct a protected equipment briefing, and document shift manager approval prior to performing work on protected equipment. This resulted in a loss of flow of cooling water to one of two in- service shutdown cooling residual heat removal heat exchangers and subsequent perturbation in reactor coolant system temperature during refueling outage 1R20. The inspectors determined that PG&E s failure to follow AD7.ID14, Assessment of Integrated Risk, Section 5.14 Performing Work on Posted Protected Equipment, was a performance deficiency within PG&Es ability to foresee and correct. This performance deficiency was considered to be more than minor because it impacted the configuration control attribute of the Mitigating Systems cornerstone and its objective to ensure the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences. Specifically, the loss of cooling flow to the RHR heat exchanger while in shutdown cooling mode resulted in a perturbation in RCS temperature of approximately 8 degrees Fahrenheit. The finding was evaluated in accordance with IMC 0609, Appendix G, Shutdown Operations Significance Determination Process, and determined to be of very low safety significance (Green) since it did not represent a loss of system safety function of at least a single train for greater than four hours. The finding had a cross- cutting aspect in the area of human performance associated with conservative bias because PG&E personnel did not use decision- making practices that emphasize prudent choices over those that are simply allowable. Specifically, despite being authorized to close component cooling water cross connect valves by the work control process, PG&E personnel did not question the impact of their actions on shutdown cooling (H.14 ).
05000313/FIN-2017001-012017Q1Arkansas NuclearFailure 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)
05000313/FIN-2017001-022017Q1Arkansas NuclearFailure to Evaluate All Required Functions for OperabilityGreen. The inspectors identified a finding and an associated non-cited violation of 10 CFR 50, Appendix B, Criterion V, Instructions, Procedures, and Drawings, for failure to evaluate the impact of all the required safety functions for operability when the valve failed to fully open during a valid demand. Specifically, the licensee failed to evaluate the operability impact on the safety function to close for the Unit 1 motor-operated borated water storage tank outlet valve CV-1408 before de-energizing and locking open the valve and declaring it operable. After the inspectors questioned this decision, the licensee declared the valve inoperable and repaired the valve operator. The licensee documented this issue in Condition Report CR-ANO-1-2017-00324. The failure to evaluate the operability impact of all required safety functions for Unit 1 motor-operated valve, CV-1408, before de-energizing and locking open the valve is a performance deficiency. 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 availability of systems that respond to initiating events to prevent undesirable consequences. Specifically, by locking the valve open, the licensee prevented Train B of the emergency core cooling system from being able to be remotely isolated from the borated water storage tank during the containment recirculation phase of a potential loss of coolant accident, which could have allowed air binding of the pumps. 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. The inspectors determined that this finding has a cross cutting aspect in the human performance area of Consistent Process, because the performance deficiency was caused by not following a consistent, systematic approach to making a decision concerning operability of the affected train. (H.13)
05000313/FIN-2017001-042017Q1Arkansas NuclearLicensee-Identified ViolationThe licensee identified that four seal injection check valves to the Unit 1 reactor coolant pumps (RCPs), which functioned as containment isolation valves, were missing internal springs required per original design. Due to the vertical orientation of the valves, the valves needed these springs to ensure that the valve disc would seat properly during reverse flow. The licensee also identified they had failed to test these ASME Code Class C check valves close safety function in accordance with ASME Code for Operation and Maintenance of Nuclear Power Plants (OM) Code. The licensee had been testing the close function by manually closing the check valves with their handwheels. Title 10 CFR Part 50.55a.(f)(4)(ii), requires in part, that ASME Code Class 3 pumps and valves must meet the inservice test requirements of ASME Code for Operation and Maintenance of Nuclear Power Plants (OM Code). The 2003 Addenda to the 2001 ASME OM Code, Subsection ISTC, Inservice Testing of Valves in Light-Water Reactor Nuclear Power Plants, Section ISTC-5220, Check Valves, Subsection ISTC-5221, Valve Obturator Movement, Paragraph (a)(1), states in part, that check valves shall be exercised by verifying that on cessation or reversal of flow, the obturator has traveled to the seat. Contrary to the above, prior to November 29, 2016, the inservice tests to verify operational readiness of RCP seal injection check valves did not comply with the applicable version of the ASME OM Code requirement to exercise check valves by verifying that on cessation or reversal of flow, the obturator has traveled to the seat. Specifically, the licensee was manually closing these stop check valves in accordance with their test procedure to satisfy inservice testing. The licensee immediately installed springs for these valves as required and wrote a test procedure to test these valves in accordance with ASME OM Code. The licensee documented the issue in their corrective action program as Condition Report CR-ANO-2016-05149. Using NRC Inspection Manual Chapter 0609, Appendix A, "The Significance Determination Process (SDP) For Findings At-Power, dated June 19, 2012, the inspectors determined 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 and heat removal components.
05000313/FIN-2017001-052017Q1Arkansas NuclearLicensee-Identified ViolationOn January 16, 2017, Unit 1 operators noticed reduced pressure and flow from service water pump C while placing it in service. The licensee declared the pump inoperable, found and removed approximately 10 feet of 12-inch polymer tube that was obstructing the suction path of the pump, and completed a successful test and inspection of the pump before returning it to service. The licensee determined that the hose was inadvertently introduced while the service water bay was open for maintenance during the fall 2016 Unit 1 refueling outage. The inspectors reviewed the licensees evaluation of pump functionality and concluded that the pump could produce enough flow and pressure to fulfill its safety function, and that the pump could withstand fully ingesting the hose without significant damage to the pump or system. Title 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. Licensee Procedure EN-MA-118, Foreign Material Exclusion, Revision 10, an Appendix B quality-related procedure, provides instructions for controlling foreign material, an activity affecting quality. Procedure EN-MA-118, Step 5.4, requires, in part, that only necessary material be allowed in the foreign material exclusion zone. Contrary to the above, between September 14, and November 25, 2016, the licensee failed to only allow necessary material in the foreign material exclusion zone. Specifically, when the Unit 1 service water pump C bay was open for maintenance, a hose was unnecessarily introduced and then left in the bay after the maintenance. The licensee documented the issue in the licensees corrective action program as Condition Report CR-ANO-1-2017-00164. To correct the issue, the licensee removed the hose, inspected and tested the pump, and inspected all other potentially affected service water bays to verify no foreign material was present. Using NRC Inspection Manual Chapter 0609, Appendix A, "The Significance Determination Process (SDP) For Findings At-Power, dated June 19, 2012, the inspectors determined the finding to be of very low safety significance (Green) because the degraded pump would still be able to perform its safety function, despite the flow capability reduction.
05000313/FIN-2017001-032017Q1Arkansas NuclearInadvertent Reactivity AdditionGreen. Inspectors documented a Green self-revealing finding and associated non-cited violation of Unit 1 Technical Specification 5.4.1.a. Specifically, the licensee failed to properly pre-plan and perform maintenance of the integrated control system equipment that can affect the performance of safety-related equipment. The licensee failed to plan and perform post-maintenance testing on newly installed integrated control system cards before returning the system to service. As a result, the licensee failed to detect a failed card. When the associated controller was placed into automatic mode, the system responded to a false demand signal that resulted in an inadvertent rod withdrawal that required prompt operator action to terminate the power increase and restore power to the original level. To correct the failed card, the licensee installed a new card that had been tested and validated prior to installation. The licensee documented this issue in Condition Report CR-ANO-1-2016-05551. Inspectors concluded that the failure to perform a post-maintenance test prior to placing a component in service is a performance deficiency. Specifically, the work order for replacing the steam generator reactor demand circuit card did not include a verification that the system was functioning properly after the replacement card was installed in the plant. The performance deficiency is more than minor because if left uncorrected, the performance deficiency has the potential to become a more significant safety concern. Specifically, if the operator had not taken prompt action to mitigate the event, it could have resulted in a more significant plant transient and could have challenged plant equipment. In accordance with Inspection Manual Chapter 0609, Attachment 4, Initial Characterization of Findings, issued October 7, 2016, and Exhibit 1 of IMC 00609, Appendix A, The Significance Determination Process (SDP) for Findings At-Power, Issued June 19, 2012, the inspectors determined the finding to be of very low safety significance (Green) because the finding is associated with the initiating events cornerstone and did not cause a reactor trip. The finding was determined to have a cross-cutting aspect in the area of human performance associated with Work Management, because the licensee did not ensure that they followed a process of planning, controlling, and executing the work activities in a formalized manner, allowing the work order to not have complete instructions for a post-maintenance test. (H.5)
05000313/FIN-2016004-042016Q4Arkansas NuclearLicensee-Identified ViolationDuring the fall 2016 Unit 1 refueling outage, the licensee foreign object search and retrieval (FOSAR) inspections in the steam generator bowls and reactor vessel identified a number of foreign objects, including an 8-inch metal rod. Discussions with the licensee indicated that some of the debris constituted foreign material that should have been prevented from being introduced into the RCS by the foreign material exclusion program. The inspectors concluded that the foreign material was most likely introduced during the previous refueling outage. During the prior operating cycle, the licensees chemistry sampling identified increased RCS activity, and subsequent fuel bundle examinations of fuel removed from the core identified wear marks through the cladding of two adjacent fuel pins. The fuel assembly with the damage was not placed back into the RCS. Since there was no evidence of broken components inside the RCS, the licensee concluded that the most likely cause was the introduction of foreign material. While it was not possible to determine whether any of the foreign material had actually caused the fuel damage, the inspectors concluded that the licensee had failed to control foreign material and prevent it from entering the RCS. Title 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. Licensee Procedure EN-MA-118, Foreign Material Exclusion, Revision 10, an Appendix B quality-related procedure, provides instructions for controlling foreign material. Procedure EN-MA-118, Step 5.5, requires, in part, that all material and tools that were introduced to the FME zone are accounted for. Contrary to the above, between January 25, and March 1, 2015, the licensee failed to ensure that all material and tools that were introduced to the FME zone were accounted for. Specifically, the licensee failed to maintain adequate FME control, leading to two damaged cladding pins and slightly elevated dose rates in the RCS piping, as well as another piece of metallic FME in the vessel, as documented in CR-ANO-1-2016-03340. This issue was documented in the licensees corrective action program under CR-ANO-1-2016-03521. Corrective actions taken include a search for the foreign material and permanent removal of the fuel assembly from the core. Prior to 2012, the NRCs Significance Determination Process in IMC 0609, Attachment 4, Phase 1 - Initial Screening and Characterization of Findings, contained guidance to screen all more than minor performance deficiencies affecting fuel barriers to very low safety significance. The inspection manual chapters were restructured in 2012, and the screening was inadvertently omitted, though the NRC was in the process of reinstating that same guidance. Therefore, after consultation with the Office of Nuclear Reactor Regulation, the inspectors determined that this finding is of very low safety significance (Green).
05000313/FIN-2016004-032016Q4Arkansas NuclearLicensee-Identified ViolationThe licensee identified that the Unit 1 emergency diesel generator governors were left in droop mode at all times, so that during a loss of offsite power the speed and frequency of the EDGs would decrease as loading increased and cause a reduction in speed and capability from safety-related motors. The licensee determined that some EDG-powered safety-related motors would not have been capable of providing the required flow rate for a short period of time, but this did not prevent them from performing their safety function. Title 10 CFR Part 50, Appendix B, Criterion V, Instruction, Procedures, & Drawings, states, in part, that activities affecting quality shall be prescribed by procedures of a type appropriate to the circumstance. Contrary to the above, as of November 2, 2016, the procedure for Unit 1 EDG operations, an activity affecting quality, was not appropriate to the circumstance. Specifically, Procedure OP-1104.036, Emergency Diesel Generator Operation, Revision 74, did not state to set the speed droop settings for both A and B EDGs to zero when not load sharing with another power source and did not specify this as a requirement for the EDGs when in an emergency standby condition. The licensee immediately set the speed droop settings for both EDGs to zero and changed the procedure. The licensee documented the issue in their corrective action program as Condition Report CR-ANO-1-2016-04333. Using NRC Inspection Manual Chapter 0609, Appendix A, "The Significance Determination Process (SDP) For Findings At-Power, dated June 19, 2012, the inspectors determined the finding to be of very low safety significance (Green) because the deficiency did not result in a loss of a safety function.
05000313/FIN-2016004-022016Q4Arkansas NuclearFailure to Design Pipe Support for VibrationGreen. The inspectors documented a self-revealed finding and associated non-cited violation of 10 CFR 50 Appendix B Criterion III for the licensees failure to verify that the decay heat removal (DHR) system drain piping configuration and supports could withstand vibrations created during low pressure and high flow conditions. As a result, a cracked weld and unisolable leak in the DHR system occurred due to high cycle fatigue caused by those conditions. To correct this issue, the licensee repaired the leaking weld and designed and installed a new piping support and piping configuration to reduce vibrations during the expected operating conditions. The licensee entered this issue into the corrective action program as Condition Report CR-ANO-1-2016-03225. The failure to design the decay heat removal system piping to withstand expected vibrations from the systems cavitating venturis is a performance deficiency. The performance deficiency is more than minor because it was associated with the design control attribute of the initiating events cornerstone and adversely affected the cornerstone objective to limit the likelihood of events that upset plant stability and challenge critical safety functions during shutdown as well as power operations. Specifically, inadequate design of the DHR system piping support resulted in a leak that could have challenged the capability of both trains of the DHR system during shutdown on September 29, 2016. The inspectors performed an initial screening of the finding in accordance with NRC Inspection Manual Chapter (IMC) 0609, "Significance Determination Process," issued October 7, 2016, and were directed to IMC 0609, Appendix G, Attachment 1, "Shutdown Operations Significance Determination Process Phase 1 Screening and Characterization of Findings, since the finding pertained to a degraded condition while the plant was shutdown. Using IMC 0609, Appendix G, Attachment 1, dated May 9, 2014, the inspectors determined that the finding required a Phase 2 evaluation. A senior reactor analyst performed a Phase 2 evaluation in accordance with IMC 0609, Appendix G, Attachment 2, Phase 2 Significance Determination Process Template for PWR during Shutdown, dated February 28, 2005. The senior reactor analyst performed a Phase 2 evaluation which used realistic break characteristics and plant configuration changes to determine the significance to be of very low safety significance (Green). 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 licensee last reviewed and modified the pipe support configuration in 1996
05000313/FIN-2016004-012016Q4Arkansas NuclearFailure to Pre-plan Walkdown to Avoid Impacting Safety BusGreen. The inspectors documented a self-revealed finding and associated non-cited violation of Unit 1 Technical Specification 5.4.1.a, for the failure to properly pre-plan and perform a pre-modification walkdown in the Unit 1 train A safety-related switchgear room so that the walkdown would not adversely affect the performance of train. As a result, licensee personnel inadvertently de-energized the A3 switchgear and associated ac buses, which resulted in the loss of one train of spent fuel pool cooling. Operators restored spent fuel pool cooling, the licensee evaluated the human error and performed a training stand-down to ensure pre-job walkdowns did not impact plant equipment. The licensee entered this issue into the corrective action program as Condition Report CR-ANO-1-2016-04356. The failure to perform a plant walkdown in a manner that did not impact safety-related switchgear is a performance deficiency. The performance deficiency is more than minor because it adversely affected the human performance attribute 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. Specifically, de-energizing the safety-related switchgear resulted in the loss of one train of spent fuel pool cooling and an increase in risk level from Green to Yellow. The inspectors evaluated the finding with NRC Manual Chapter 0609, Appendix A, The Significance Determination Process (SDP) for Findings At-Power, dated June 19, 2012, Exhibit 3, Barrier Integrity Screening Questions, because the appendix provides the most applicable guidance, regardless of whether the unit was at-power or shutdown. The inspectors determined that the finding screened as having very low safety significance (Green) because the finding did not cause the spent fuel pool to exceed the maximum analyzed temperature, did not damage fuel cladding, did not result in a loss pool water inventory below the minimum analyzed level, and did not affect the pool neutron absorber or soluble boron concentration. The inspectors determined this finding has a cross-cutting aspect in the human performance area of 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)
05000313/FIN-2016003-042016Q3Arkansas NuclearEA-16-143, Enforcement Discretion for Tornado-Generated Missile Protection NoncompliancesAppendix A to 10 CFR 50, General Design Criteria for Nuclear Power Plants, Criterion 2, Design Bases for Protection Against Natural Phenomena, states, in part, that SSCs important to safety shall be designed to withstand the effects of natural phenomena, such as tornadoes. Criterion 4, Environmental and Dynamic Effects Design Basis, states, in part, that SSCs important to safety shall be appropriately protected against dynamic effects including missiles which may result from events and conditions outside the nuclear power unit. As part of their response to external flood boundary degradation, the licensee performed a review of external hazard protection at the site, which included protection against tornado-generated missiles required by the current licensing basis for each unit. During the review, on four separate occasions, the licensee identified plant areas containing safety-related SSCs that could be susceptible to tornado missiles: Unit 1 Upper South Electrical Penetration Room Unit 1 Cable Spreading Room Unit 1 Controlled Access Area Unit 1 Vital Switchgear In each case, the licensee identified low-probability scenarios where one or more tornado-generated missiles could penetrate doors, walls, and other building features that were not fully qualified, and subsequently damage equipment that was important to safety inside the affected rooms. Details about the date of discovery, affected SSCs, condition report numbers, compensatory actions taken by the licensee, notifications made to the NRC, and affected technical specification actions for each susceptible area are listed in Attachment 3 of this report. Relevant Enforcement Discretion Policy On June 10, 2015, the NRC issued Enforcement Guidance Memorandum (EGM) 15-002, Enforcement Discretion for Tornado-Generated Missile Protection Noncompliance. (ML15111A269) The EGM referenced a bounding generic risk analysis performed by the NRC staff that concluded that tornado missile vulnerabilities pose a low risk significance to operating nuclear plants. Because of this, the EGM described the conditions under which the NRC staff may exercise enforcement discretion for noncompliances with the current licensing basis for tornado-generated missile protection. Specifically, if the licensee could not meet the technical specification required actions within the required completion time, the EGM allows the staff to exercise enforcement discretion provided the licensee implements initial compensatory measures prior to the expiration of the time allowed by the limiting condition for operation. The compensatory actions should provide additional protection such that the likelihood of tornado missile effects are lessened. The EGM then requires the licensee to implement more comprehensive compensatory measures within approximately 60 days of issue discovery. The compensatory measures must remain in place until permanent repairs are completed, or until the NRC dispositions the non-compliance in accordance with a method acceptable to the NRC such that discretion is no longer needed. In addition, the issue must be entered into the licensees corrective action program. Because EGM 15-002 listed Arkansas Nuclear One as a Group A plant, enforcement discretion will expire on June 10, 2018. However, the EGM did not provide for enforcement discretion for any related underlying technical violations; the EGM specifically requires that any associated underlying technical violations be assessed through the enforcement process. Licensee Actions For each of the examples listed above, the licensee declared the affected systems inoperable and complied with the applicable technical specification action statement(s), initiated a condition report, invoked the enforcement discretion guidance, implemented prompt compensatory measures, and returned the SSCs to an operable status. The licensee instituted compensatory measures intended to reduce the likelihood of tornado missile effects that included developing actions to be taken if a tornado watch is predicted or issued for the area to ensure the operability or restore redundant equipment during severe weather, and actions to be taken if a tornado warning is issued, including pre-staging operators in safe, strategic locations to promptly implement mitigative actions, and verifying the readiness of equipment and procedures dedicated to the Diverse and Flexible Coping Strategy (FLEX). Other specific compensatory actions for the individual areas are listed in Attachment 3. NRC Actions The inspectors review addressed the material issues in the plant, and whether the measures were implemented in accordance with the guidance in EGM 15-002. The inspectors also evaluated whether the measures would function as intended and were properly controlled. The inspectors verified through inspection that the EGM 15-002 criteria were met in each case. Therefore, the staff determined that it was appropriate to exercise enforcement discretion and not take enforcement action for the technical specification requirements listed in Attachment 3 of this report, provided the noncompliances are resolved by June 10, 2018 (EA-16-143). The inspectors did not fully review the underlying circumstances that resulted in the technical specification violations. As stated in EGM 15-002, violations of other requirements which may have contributed to the technical specification violations will be evaluated independently of EGM implementation. The inspectors will verify restoration of compliance and assess the underlying circumstances in a follow-up inspection tracked under Licensee Event Reports 05000313/2016-002-00 and 05000313/2016-003-00, and any updates or additional licensee event reports that the licensee issues.
05000323/FIN-2016002-012016Q2Diablo CanyonMisplaced Spent Fuel Assembly in the Spent Fuel PoolThe inspectors reviewed a self-revealed, non-cited violation of Technical Specification (TS) 5.4.1.a, Procedures, for the licensees failure to place a spent fuel assembly in its correct location in the spent fuel pool (SFP) in accordance with Procedure OP B-8H, Spent Fuel Pool Work Instructions. Specifically, the fuel handling crew moved spent fuel assembly TT69 to location E-37 rather than its intended location E-27. In response to this error, reactor engineering performed a technical specification verification in order to ensure that fuel assembly TT69 could remain in Cell E-37. The licensee suspended further fuel movements pending corrective action and remediation of the operators. The licensee entered this into the corrective action program as Notifications 50846834 and 50847067. The licensees failure to place a spent fuel assembly in its correct location in the SFP was a performance deficiency. The performance deficiency is more than minor, and therefore a finding, because it is associated with the configuration control attribute of the Barrier Integrity Cornerstone and adversely affected the cornerstone objective to provide reasonable assurance that physical design barriers (fuel cladding, reactor coolant system, and containment) protect the public from radionuclide releases caused by accidents or events. Using Inspection Manual Chapter 0609, Attachment 04, Initial Characterization of Findings, and Appendix A, Exhibit 3, Barrier Integrity Screening Questions, the inspectors determined that the finding was of very low safety significance (Green) because: (1) the finding did not adversely affect decay heat removal capabilities from the spent fuel pool causing the pool temperature to exceed the maximum analyzed temperature limit specified in the site-specific licensing basis, (2) the finding did not result from fuel handling errors, dropped fuel assembly, dropped storage cask, or crane operations over the SFP that caused mechanical damage to fuel clad and a detectible release of radionuclides, (3) the finding did not result in a loss of spent fuel pool water inventory decreasing below the minimum analyzed level limit specified in the site-specific licensing basis, and (4) the finding did not affect the SFP neutron absorber, fuel bundle misplacement (i.e., fuel loading pattern error) or soluble Boron concentration. This finding had a cross-cutting aspect in the area of human performance associated with avoiding complacency. Specifically, individuals failed to recognize and plan for the possibility of mistakes, latent issues, and inherent risk, even while expecting successful outcomes and individuals failed to implement appropriate error reduction tools (Section 4OA2). (H.12)
05000313/FIN-2016007-172016Q1Arkansas NuclearDetermine Impact of Modifying Fire Seals for Flood ProtectionThe team identified an unresolved item related to ability to meet the requirements of License Condition 2.C.(8) and 2.C.(3)(b), Fire Protection Program, in Units 1 and 2, respectively. Specifically, the team identified ANO had modified numerous fire rated seals to also provide a flood protection barrier without ensuring existing fire protection requirements continued to be met. ANO Units 1 and 2 used a 3- hour fire rated silicon foam material to seal floor and walls penetrations in order to provide adequate separation to prevent the spread of fire between fire areas. ANO determined that numerous exiting fire seals were also required to provide flood protection. To provide an 3-hour fire barrier and also be capable of withstanding a design basis flood, ANO issued design changes to use several materials, such as Polywater FST Foam Sealant, Promatec Product 12 (P12), Sylgard, and Promatec High Density Silicone Elastomer (HDSE and HDSE-IR), to create dual purpose seals. The team determined that HDSE, HDSE-IR and Sylgard have been tested as a 3-hour fire barrier and tested satisfactorily to provide adequate flood protection. However, ANO could not produce documentation to show that fire rating testing or qualification testing had been performed for the new dual function seals using P12 and Polywater. This was documented in CR-ANO-C-2016-00490. ANO has determined that the population of the non-qualified seals was 139 (96 containing Polywater and 43 containing P12). ANO stated that all of the new dual function seals using P12 consist of the flood protective layer of P12 being placed on top of the existing originally qualified 10 inch fire silicone seal, and that no credit was given to the P12 layer to provide any additional fire protection capabilities. The P12 has been tested by Promatec with silicone seals for flood and was flood tested by the station for use with silicone foam seals. Therefore, ANO believes that no negative chemical reactions can be expected. ANO installed Polywater material either on top of the currently installed fire barrier seal, or in electric conduits that are not required to have a fire seal present. Polywater is designed to create an air and watertight barrier suitable for use in conduits. ANO did not remove any portion of the originally qualified silicon foam fire seals, therefore the flood protection layer of Polywater was applied on top of the existing qualified fire seal. As part of the approved Fire Protection Program, a periodic visual inspection of fire penetration seals is required by TRM 3.7.12.3 and TRM 3.7.5, for Units 1 and 2 respectively, such that 10 percent of the total fire seal population is inspected each year. These inspections are conducted per Unit 1 procedure OP 1405.016, U-1, Penetration Fire Barrier Visual Inspections, and Unit 2 procedure OP 2405.016, U-2, Penetration Fire Barrier Visual Inspections. The team reviewed the inspection procedures and interviewed the fire protection engineers. The team was concerned that for many of the new dual function seals, the original fire rated and qualified seal was no longer accessible for performance of required visual inspections. The team was concerned that because the silicone fire seals are no longer accessible for inspection, the intent of the required fire seal inspection to detect surface flaws or damage to indicate potential underlying damage has occurred to the qualified fire penetration system per the fire protection program could not be met. The team concluded that not having fire rating qualification testing for the existing configuration of some fire seals, and the inability to perform required periodic visual inspections for newly modified fire seals, was a performance deficiency that was reasonably within ANOs ability to foresee and prevent. Since ANO has not yet completed the evaluation or fire testing qualification of the modified seals, the team was unable to evaluate the overall impact of this condition or classify the performance deficiency. ANO intended to complete the evaluation of these issues and document the results in CR-ANO-C-2016-00490. Some of the actions being considered include performing required 3-hour fire testing in representative dual function configurations containing Polywater or P12; and doing a feasibility study for removal and replacement of these seals with fire and flood qualified materials. The team concluded that further review is necessary in order to properly evaluate and disposition the significance of this condition. Specifically, the NRC will need to review the following: ANOs evaluation, extent of condition, and disposition and/or testing results of the non-qualified dual function fire/flood seals; and the significance of the non-qualified population (139 seals containing Polywater or P12). This item is being treated as an unresolved item (URI) 05000313/2016007-17 and 05000368/2016007-17, Fire Seals Modified for Flood with Material not Qualified for Fire and Inability to Perform Required Periodic Visual Inspection.
05000368/FIN-2016001-042016Q1Arkansas NuclearFailure to Inject Service Water with Corrosion Inhibitors during Refueling OutagesThe inspectors reviewed a self-revealing Green finding and an associated non-cited violation for the failure to follow Procedure OP-1052.007, Secondary Chemistry Monitoring, Revision 040. Specifically, the licensee failed to inject corrosion inhibiting chemicals into Unit 2 service water during refueling outages, which resulted in increased corrosion of the service water system. This issue was entered into the corrective action program as Condition Report CR-ANO-2-2016-02879. The failure to inject corrosion inhibitors into Unit 2 service water during refueling outages resulted in increased corrosion of the service water system is a performance deficiency. The performance deficiency is more than minor because it adversely affected the human performance attribute of the mitigating system 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 performance deficiency adversely affected the structural strength of service water system boundaries. Using NRC Inspection Manual Chapter 0609 Appendix A, The Significance Determination Process (SDP) for Findings At-Power, Dated June 19, 2012, the inspectors screened the finding as having very low safety significance because it is a deficiency affecting the design or qualification of a mitigating SSC, but the SSC maintained its operability. The inspectors determined that this finding had a cross-cutting aspect in the human performance area of Avoid Complacency, because the licensee failed to recognize the potential consequences of isolating chemical injection to the service water during outages, which contributed to degradation.
05000313/FIN-2016001-062016Q1Arkansas NuclearLicensee-Identified ViolationTitle 10 CFR 50.65(a)(4), states in part, that before performing maintenance activities (including but not limited to surveillance, post-maintenance testing, and corrective and preventive maintenance), the licensee shall assess and manage the increase in risk that may result from the proposed maintenance activities. Contrary to the above, before performing maintenance activities on February 24, 2016, the licensee failed to assess and manage the increase in risk that resulted from maintenance activities in the switchyard. Specifically, the licensee performed maintenance on the supervisory control circuits associated with the startup transformer breakers during the Unit 2 forced outage. This work had already begun when Entergy executives on a fleet call questioned the impact of maintenance on the breakers that supply power to safety-related buses while Unit 2 is shutdown. Further review indicated that the impact was more extensive than previously thought. For immediate corrective actions, control room operators contacted the switchyard coordinator and rescheduled the supervisory control circuit work. Because the finding affects the licensees assessment of risk associated with performing maintenance activities, NRC Manual Chapter 0609, Attachment 4, Initial Characterization of Findings, dated June 19, 2012 directs significance determination using NRC Manual Chapter 0609, Appendix K, Maintenance Risk Assessment and Risk Management Significance Determination Process, dated May 19, 2005. The finding was determined to be Green because the incremental core damage probability deficit was less than 1E-6 and the incremental large early release frequency probability deficit was less than 1E-7. A senior reactor analyst estimated incremental core damage probability deficit to be 1.9E-8 for Unit 1 and 1.2E-8 for Unit 2 using the Standardized Plant Analysis Risk models for Unit 1 (Revision 8.19) and Unit 2 (Revision 8.26) run on SAPHIRE, Version 8.1.2. The licensee entered the issue into the corrective action program as Condition Report CR-ANO-C-2016-00908. Licensee-identified violations are not assigned cross-cutting aspects.
05000368/FIN-2016001-032016Q1Arkansas NuclearBlocked Drain Results in Emergency Feedwater Pump InoperabilityThe inspectors documented a self-revealing Green finding with an associated non-cited violation of 10 CFR Part 50, Appendix B, Criterion XI, Test Control, for the failure to verify that the floor drains in the Unit 2 turbine-driven emergency feedwater pump room would pass the amount of water added to the drain during operation of the pump in order to prevent the pump from becoming submerged. As a result, the licensee was unaware that the turbine-driven emergency feedwater pump room drain had become blocked until water began pooling in the room during a pump test. Upon discovery, the licensee stopped the pump, declared the train inoperable, and cleared the drain. This finding was entered into the licensees corrective action program as Condition Report CR-ANO-2-2016-0384. The failure to verify that the Unit 2 turbine-driven emergency feedwater pump room drain would pass the water added to the drains during operation of the turbine-driven emergency feedwater pump is a performance deficiency. The finding is more than minor because it adversely affected the protection against external factors (i.e., flood hazard) attribute of the mitigating systems cornerstone to ensure the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences (i.e., core damage). Specifically, the failure to detect a clogged drain affected the availability of the emergency feedwater system by potentially flooding the room and failing the pump. The inspectors evaluated the finding using Manual Chapter 0609 Appendix A, The Significance Determination Process (SDP) for Findings At-Power. 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. A senior reactor analyst performed a detailed risk evaluation and estimated the total increase in core damage frequency to be 7.7E-7/year, and therefore the finding had very low safety significance (Green). The inspectors determined that this finding did not have a cross-cutting aspect because the most significant contributor, inadequate documentation of the pump design requirements during initial plant construction, does not reflect current licensee performance.
05000368/FIN-2016001-022016Q1Arkansas NuclearFailure to Follow Design Control Requirements for Pump Seal Cooler ReplacementsThe inspectors identified a Green finding and an associated non-cited violation of 10 CFR 50, Appendix B, Criterion III, Design Control, for the failure to ensure the suitability of materials used in safety-related equipment. Specifically, the licensee made a change to the material used in ten safety-related pump bearing coolers without considering the potential effects of corrosion. As a result, a drain plug corroded and caused service water to spray, rendering two safety-related pumps inoperable. This issue was entered into the corrective action program as Condition Report CR-ANO-2-2016-00550. The failure to consider the potential for corrosion in the design of safety-related equipment is a performance deficiency. The performance deficiency is more than minor because it adversely affected the design control attribute of the mitigating system 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, in each of the three examples, the licensee made changes to the plant where the potential effects of corrosion on safety-related equipment was not considered. Using Inspection Manual Chapter 0609, Appendix A, The Significance Determination Process (SDP) for Findings At-Power, the inspectors screened this finding as Green, because the finding did not represent an actual loss of safety function. The inspectors determined that this finding did not have a cross-cutting aspect because the most significant contributor did not reflect current licensee performance.
05000313/FIN-2016001-052016Q1Arkansas NuclearFailure to Identify and Repair Intermittent Card Failure Leads to a Reactor TripThe inspectors reviewed a self-revealing Green finding for the failure to fully understand a malfunction which resulted in putting susceptible cards back into the Unit 1 integrated control system. In 2014, a failure caused a feedwater transient, which operators successfully mitigated. Troubleshooting identified and repaired some of cards susceptible to the intermittent problem. The licensee reinstalled cards that had not been repaired in the integrated control system, which later caused a feedwater transient and subsequent manual reactor trip on December 15, 2015. The licensee documented the issue in Condition Report CR-ANO-1-2015-04178 and replaced the cards. The failure to fully understand a malfunction, which resulted in putting susceptible cards back into the Unit 1 integrated control system, is a performance deficiency. The finding is more than minor because it adversely affected the equipment performance attribute of the initiating event cornerstone to limit the likelihood of events that upset plant stability and challenge critical safety functions during shutdown as well as power operations. Specifically, the licensee placed the suspect cards back into the integrated control system, which caused a feedwater transient and contributed to a subsequent manual reactor trip. Using NRC Manual Chapter 0609, Appendix A, The Significance Determination Process (SDP) for Findings At-Power, dated June 19, 2012, Exhibit 1, Initiating Events Screening Questions, the finding screened as having very low safety significance (Green) because the deficiency resulted in a reactor trip, but mitigation equipment remained unaffected. Specifically, main feedwater remained available. The inspectors determined this finding has a problem identification and resolution cross-cutting aspect in the area of Evaluation, because the primary cause of the performance deficiency involved the failure to thoroughly evaluate a 2014 integrated control system failure so that the resolution addressed the cause commensurate with safety significance.
05000313/FIN-2016001-012016Q1Arkansas NuclearFailure to Assess and Manage Hot Work RiskThe inspectors identified a Green finding and an associated non-cited violation of 10 CFR 50.65(a)(4), Requirements for Monitoring the Effectiveness of Maintenance at Nuclear Power Plants, for the failure to assess and manage the increase in risk due to performing hot work near risk-significant Unit 1 non-vital switchgear. Specifically, the licensee failed to identify the work as having low integrated risk, and implement required risk management actions to protect available fire pumps and brief the fire brigade. As immediate corrective actions, the licensee stopped the hot work until they completed a risk assessment and risk management actions. This finding was entered into the licensees corrective action program as Condition Report CR-ANO-1-2016-00348. The failure to assess and manage the increase in risk of performing hot work near risk-significant Unit 1 non-vital switchgear is a performance deficiency. The finding is more than minor because it adversely affected the protection against external factors (i.e., fires) attribute of the initiating event cornerstone to limit the likelihood of events that upset plant stability and challenge critical safety functions during shutdown as well as power operations. Specifically, the licensee failed to assess the potential for hot work to cause a fire, and manage the risk to critical safety functions. Because the finding affects the assessment of risk associated with performing maintenance activities, NRC Manual Chapter 0609, Attachment 4, Initial Characterization of Findings, directs significance determination using NRC Manual Chapter 0609, Appendix K, Maintenance Risk Assessment and Risk Management Significance Determination Process. A regional senior reactor analyst used Manual Chapter 0609, Appendix K, Flowchart 2, Assessment of Risk Management Actions, dated May 19, 2005, to assess the significance of the finding. The licensee site probabilistic risk assessment engineer provided information which estimated the incremental core damage probability deficit of 3.3E-10. The analyst confirmed similar results using the NRC probabilistic risk assessment model. The incremental large early release probability deficit was conservatively estimated to be equal to the incremental core damage probability deficit. Since this issue dealt only with the failure to take risk management actions, Flowchart 2, Assessment of Risk Management Actions, of Appendix K was used. In accordance with Flowchart 2, because the incremental core damage probability deficit was less than 1E-10 and the incremental large early release probability deficit was less than 1E-7, the finding screened as having very low safety significance (Green). The inspectors determined this finding has a problem identification and resolution cross-cutting aspect in the area of Teamwork, because the most significant contributor involved the failure to communicate and coordinate activities across organizational boundaries to ensure nuclear safety is maintained. Specifically, work groups did not inform operations work control personnel that hot work was part of the intended work.
05000445/FIN-2015005-032015Q4Comanche PeakInadequate Compensatory Measures for Seismic Monitoring System MaintenanceThe inspectors identified a non-cited violation of 10 CFR 50.54(q)(2) for a failure to meet planning standard 10 CFR 50.47(b)(4) during periodic outages of the seismic monitoring system. Specifically, during planned maintenance on the seismic monitoring system, inspectors determined that the system would not be able to perform its function of alerting control room staff of an entry condition into the emergency action levels for a seismic event, and the specified compensatory measures were not adequate. The licensee implemented correction actions to establish viable compensatory measures for periods when the seismic monitoring system is unavailable. The licensee entered these issues into corrective action program as Condition Report CR-2016-000091. The licensees failure to maintain the effectiveness of their emergency plan was a performance deficiency. The performance deficiency was more than minor, and therefore a finding, because it affected the ERO Performance attribute of the Emergency Preparedness cornerstone and impacted the cornerstone objective to ensure that the licensee is capable of implementing adequate measures to protect the health and safety of the public in the event of a radiological emergency. Using Inspection Manual Chapter 0609, Attachment 04, Initial Characterization of Findings, and Inspection Manual Chapter 0609, Appendix B, Emergency Preparedness Significance Determination Process, the inspector determined that the violation is of very low safety significance (Green) because the finding represented a failure to comply with planning standard (b)(4), and, using table 5.4-1, was screened as a Green finding because an emergency action level initiating condition was rendered ineffective such that an Alert would be declared in a degraded manner for a seismic event, but no Site Area Emergency or General Emergency initiating conditions were affected. The violation was entered into the licensees corrective action program as CR-2016-000091. The inspectors determined that this finding has a problem identification and resolution crosscutting aspect associated with resolution, because the licensee failed to take appropriate corrective action after they recognized the inadequacy of their compensatory measures (P.3).
05000445/FIN-2015005-062015Q4Comanche PeakFailure to Barricade High Radiation AreasThe inspector identified a non-cited violation (NCV) of Technical Specification 5.7.1.a, with two examples, associated with not barricading High Radiation Areas (HRAs) with dose rates not exceeding 1.0 rem/hour at 30 centimeters from the radiation source. Specifically, access to the HRA containment trashracks and access to the HRA reactor cavity before flood up were not barricaded to prevent entry. The licensee took immediate corrective action to barricade the associated HRAs to restrict access and entered this issue into the corrective action program as CR-2015-009095 and CR-2015-009303. The failure to barricade high radiation areas in accordance with TS 5.7.1.a was a performance deficiency. The inspector determined that the performance deficiency was more than minor, and therefore a finding, because it impacted the program and process attribute of the Occupational Radiation Safety Cornerstone and adversely affected the cornerstone objective to ensure adequate protection of worker health and safety from exposure to radiation from radioactive material during routine civilian nuclear reactor operation. Specifically, not barricading HRAs could lead to inadvertent worker entry into high dose rate areas without knowledge of the radiological conditions. The finding was assessed using IMC 0609, Appendix C, Occupational Radiation Safety Significance Determination Process, dated August 19, 2008, and was determined to be of very low safety significance (Green) because the problem was not an ALARA planning issue; there was no overexposure, nor substantial potential for an overexposure; and the licensees ability to assess dose was not compromised. The finding was associated with a crosscutting aspect of Resolution in Problem Identification and Resolution area. Specifically, the organizations corrective actions to address HRA issues raised by Nuclear Oversight, the NRC and independent assessments in a timely manner commensurate with their safety significance have not been effective (P.3).
05000445/FIN-2015005-012015Q4Comanche PeakIncorrect Visual Resolution Requirements in Augmented Dissimilar Metal Weld Visual Examination ProceduresThe inspectors identified a non-cited violation of 10 CFR 50, Appendix B, Criterion IX, Control of Special Processes, because the licensee failed to assure that visual examination activities for the reactor vessel dissimilar metal nozzle welds and bottommounted instrumentation nozzles were accomplished in accordance with the visual acuity requirements of ASME Code Case N-722-1. In response to the issue, for Unit 2, the licensee scheduled reexamination of the welds prior to the end of the outage, and, for Unit 1, performed a reasonable degradation evaluation to determine that reexamination of the welds could be delayed to the next outage. This finding was entered into the corrective action program as Condition Report 2015-009586. The inspectors determined that the failure to assure visual examination activities were accomplished in accordance with the visual acuity requirements of ASME Code Case N-722-1 was a performance deficiency. The performance deficiency was more than minor, and therefore a finding, because if left uncorrected, the performance deficiency would have the potential to lead to a more significant safety concern. Specifically, routinely performing examinations with incorrect visual acuity requirements of N-722-1 has the potential to lead to missed opportunities to identify and correct relevant indications in reactor coolant system pressure boundaries. In accordance with Inspection Manual Chapter MC 0609, Attachment 4, Significance Determination Process Initial Characterization, the inspectors determined that this finding affected the Initiating Events cornerstone as a primary system LOCA initiator contributor. In accordance with Inspection Manual Chapter 0609, Appendix A, The Significance Determination Process (SDP) for Findings At-Power, dated June 19, 2012, Exhibit 1, Initiating Events Screening Questions, the finding screened as having very low safety significance (Green) because after a reasonable assessment of degradation, the finding did not result in exceeding the RCS leak rate for a small LOCA and did not affect other systems used to mitigate a LOCA. The finding does not have a crosscutting aspect because the most significant contributor is not reflective of current licensee performance.
05000382/FIN-2015004-012015Q4WaterfordFailure to Properly Pre-Plan and Perform Maintenance on the Core Element Assembly CalculatorsThe inspectors reviewed a self-revealing, non-cited violation of Technical Specification 6.8.1.a, associated with the licensees failure to properly pre-plan and perform maintenance in accordance with EN-DC-153, Preventative Maintenance Component Classification. The licensee entered this condition into their corrective action program as condition report CR-WF3-2015-06438. The licensee restored compliance by properly classifying the components as High Critical in accordance with EN-DC-153, Revision 2, and by initiating development of appropriate preventative-maintenance for the control element assembly calculators (CEACs). In addition, the licensee initiated work to improve the reliability of the CEACs, including reviewing card refurbishments to ensure circuit card reliability is enhanced. The performance deficiency was more than minor because it is associated with the Equipment Performance attribute of the Initiating Events Cornerstone and adversely affected the cornerstone objective to limit the likelihood of events that upset plant stability and challenge critical safety functions during shutdown as well as power operations. Specifically, inappropriate preventative maintenance on the circuit cards associated with the CEACs ultimately resulted in a plant trip on October 3, 2015. The inspectors screened the finding in accordance with NRC Inspection Manual Chapter (IMC) 0609, Significance Determination Process. Using IMC 0609, Appendix A, The Significance Determination Process (SDP) for Findings At-Power, the inspectors determined that the finding was of very low significance (Green) because the finding did not cause a trip and the loss of mitigation equipment relied upon to transition the plant from the onset of the trip to a stable shutdown condition. Because the performance deficiency occurred in 2008, the inspectors concluded that the finding does not reflect current licensee performance and therefore did not assign a cross-cutting aspect.
05000445/FIN-2015005-092015Q4Comanche PeakLicensee-Identified ViolationTitle 10 CFR Part 50, Appendix B, Criterion XI, "Test Control," states, in part, A test program shall be established to assure that all testing required to demonstrate that structures, systems, and components will perform satisfactorily in service is identified and performed in accordance with written test procedures which incorporate the requirements and acceptance limits contained in applicable design documents. Contrary to the above, on October 20, 2015, the licensee failed to incorporate adequate acceptance limits in a quality-related written procedure that demonstrates components will perform satisfactorily. Specifically, the licensee failed to use appropriate acceptance limits for integrated testing of the station emergency diesel generators. Using Inspection Manual Chapter 0609, Appendix A, The Significance Determination Process (SDP) for Findings At-Power, Exhibit 2, Mitigating Systems Screening Questions, dated June 19, 2012, the finding was determined to be of very low safety significance (Green) because the finding: (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 safetysignificant 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-2015-009990.
05000445/FIN-2015005-082015Q4Comanche PeakLicensee-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 October 14, 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 enter the operability determination process, as required by Station Procedure STI-442.01, step 6.1, when a degraded or nonconforming condition was identified associated with incorrectly performed visual examination required by the ASME code. 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 safetysignificant 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-2015-009586.
05000445/FIN-2015005-072015Q4Comanche PeakLicensee-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.
05000445/FIN-2015005-052015Q4Comanche PeakFailure to Follow Procedure When Disabling A Hazard BarrierThe inspectors identified a finding associated with the licensees failure to follow procedural requirements for disabling a hazard barrier. Specifically, Station Procedure STA 696, Hazard Barrier Controls, Revision 2, requires that appropriate temporary barriers be prescribed when a hazard barrier is impaired. However, in support of an auxiliary, safeguards and fuel building negative pressure test, the licensee failed to follow Procedure STA 696 and incorrectly credited alternate doors to protect safety-related equipment from the effects of a high-energy line break when disabling the primary hazard barrier. The licensee implemented corrective actions to correctly assess the activity and implemented appropriate risk management actions. The licensee entered the finding into corrective action program as Condition Report CR-2015-005583. The licensees failure to follow station procedures when crediting temporary hazard barriers was a performance deficiency. The performance deficiency was more than minor, and therefore a finding, because it was associated with the equipment performance attribute of the Mitigating Systems Cornerstone and affected the cornerstone objective to ensure availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences. Specifically, opening the high energy line break door without an appropriate temporary barrier in place removed a credited barrier for safety-related electrical equipment. Using Inspection Manual Chapter 0609, Appendix A, The Significance Determination Process (SDP) for Findings At-Power, Exhibit 2, Mitigating Systems Screening Questions, dated June 19, 2012, the finding was determined to be of very low safety significance (Green) because the finding: (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 safetysignificant for greater than 24 hours in accordance with the licensees maintenance rule program. The inspectors determined that this finding does not have a cross-cutting aspect because the most significant contributor of this finding would have occurred more than three years ago, and is not reflective of current licensee performance.
05000445/FIN-2015005-042015Q4Comanche PeakFailure to Identify Conditions Adverse to QualityThe inspectors identified two examples of a non-cited violation of 10 CFR 50, Appendix B, Criterion XVI, Corrective Action, for the licensees failure to identify conditions adverse to quality. Specifically, in two separate instances involving extent of condition reviews for grease on 6.9 kV breaker stabs and degraded piping in the Unit 1 service water system, the licensee failed to identify conditions adverse to quality that were reasonably within their ability to identify. As a result, the licensee failed to; 1) identify 24 additional breakers that were in a degraded condition due to grease on secondary stabs, and 2) identify a section of service water piping that was below the ASME minimum wall thickness. The licensee implemented immediate corrective actions by entering the issues into the corrective action program for resolution and performed an operability determination for the identified degraded conditions. The licensee entered these issues into the corrective action program as Condition Reports CR-2015-009992 and CR-2015-010120. The licensees failure to identify conditions adverse to quality for quality related systems was a performance deficiency. The performance deficiency was more than minor, and therefore a finding, because it affected the equipment performance 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, the failure to identify degraded conditions could affect the reliability or availability of multiple safety related systems. Using Inspection Manual Chapter 0609, Attachment 04, Initial Characterization of Findings, and Appendix A, The Significance Determination Process (SDP) for Findings At-Power, Exhibit 1, Initiating Events Screening Questions, dated June 19, 2012, the finding was determined to be of very low safety significance (Green) because the finding is a deficiency affecting the design or qualification of a mitigating SSC, but the SSC maintained its operability. The finding has a problem identification and resolution cross-cutting aspect associated with evaluation, in that, the licensee failed to thoroughly evaluate issues to ensure that resolutions address extent of conditions. Specifically, the licensee failed to adequately consider the extent of the degraded conditions on similar safety related components (P.2).
05000445/FIN-2015005-022015Q4Comanche PeakFailure to Take Appropriate Maintenance Rule Corrective Actions for the 6.9 kV AC SystemThe inspectors identified a non-cited violation of 10 CFR Part 50.65(a)(1), for the failure to establish goals that provide reasonable assurance that the 6.9 kV electrical distribution system is capable of fulfilling its intended functions. Specifically, the 6.9 kV electrical distribution system had been in maintenance rule (a)(1) status since 2009 due to the failure of breakers to close on demand. Subsequently, in 2013 and 2015 there were additional breaker failures, which exceeded the established performance criteria, and were due to causes not previously evaluated. These additional failures were determined to be due to inadequate maintenance, but the licensee did not re-evaluate the established goals and revise the corrective actions to address these additional failures. The licensee implemented corrective actions to re-evaluate the goals and corrective actions for the 6.9 kV AC system. The licensee entered this issue into the corrective action program as Condition Report CR-2015-009077. The licensees failure to evaluate existing goals and corrective actions for a system that did not meet established performance goals was a performance deficiency. The performance deficiency was more than minor, and therefore a finding, because it affected the equipment performance 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, the failure to take appropriate corrective actions adversely affected the reliability of a system scoped in the plant's maintenance rule program. Using Inspection Manual Chapter 0609, Appendix A, The Significance Determination Process (SDP) for Findings At-Power, Exhibit 2, Mitigating Systems Screening Questions, dated June 19, 2012, the finding was determined to be of very low safety significance (Green) because the finding: (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 finding has a human performance cross-cutting aspect associated with procedure adherence, in that, the licensee failed to follow maintenance rule implementing procedures. (H.8).
05000313/FIN-2013009-022013Q4Arkansas NuclearFailure to Maintain Adequate Staffing for Operators to Perform a Simultaneous Alternative Shutdown of Both Units and Staff the Fire BrigadeThe team identified an Unresolved Item (URI) concerning the failure to implement and maintain in effect all provisions of the approved fire protection program as defined by License Conditions 2.C.(8) for Unit 1 and 2.C.(3)(b) for Unit 2. Specifically, the licensee failed to maintain adequate staffing for operators to perform a simultaneous alternative shutdown of both units and staff the fire brigade. Further NRC staff evaluations will be required to determine if this issue is more than minor. The licensee provided the minimum operations shift staffing requirements in Procedure EN-OP-115, Conduct of Operations, Revision 14. This procedure required that the Unit 1 shift be comprised of a shift manager, control room supervisor, shift technical advisor, two licensed control board operators, two non-licensed auxiliary operators, a waste control operator, and a communicator. This procedure required the same staffing for Unit 2, but it noted that the Unit 2 communicator could serve as the alternate shutdown operator (a Unit 2 specific position). The licensee would use Procedure 1203.002, Alternate Shutdown, Revision 24, to perform an alternative shutdown for Unit 1 and Procedure 2203.014, Alternate Shutdown, Revision 26, to perform an alternative shutdown for Unit 2. The alternative shutdown procedure for Unit 1 required actions from the shift manager, control room supervisor, shift technical advisor, two control board operators, and two auxiliary operators. The alternative shutdown procedure for Unit 2 required actions from the shift manager, control room supervisor, shift technical advisor, two control board operators, two auxiliary operators, and the alternate shutdown operator. The licensee only required one communicator to respond to the technical support center to make the required notifications. The licensee would use Procedure 1203.029, Remote Shutdown, Revision 10, to perform a remote shutdown for Unit 1. The remote shutdown procedure required actions from the shift manager, control room supervisor, and two control board operators. Unlike the alternative shutdown procedure, it did not require actions from the two auxiliary operators. The licensee delineated operator responsibilities for alternative and remote shutdowns for both units in Calculation CALC-85-E-0086-02, Manual Action Feasibility and Common Results, Revision 4. The team noted that this calculation was not consistent with the current staffing. The calculation had not been updated after the 2007 addition of an auxiliary operator position or the 2012 addition of an alternate shutdown operator position for Unit 2. The team determined through discussions with the licensee that the fire brigade was composed of four non-licensed operators and one security officer. The waste control operator from each unit was assigned to the fire brigade and designated as the potential fire brigade leader, depending on the unit affected. In the event of an alternative shutdown of Unit 2, the licensee credited the waste control operator from Unit 2 as the fire brigade leader and the waste control operator from Unit 1, two auxiliary operators from Unit 1, and the security officer as the remaining fire brigade members. The licensee discussed operator responsibilities for an alternative shutdown of Unit 2 coincident with a remote shutdown of Unit 1, but did not discuss operator responsibilities for a simultaneous alternative shutdown of both units. The team concluded that the licensee failed to maintain adequate staffing for operators to perform a simultaneous alternative shutdown of both units and staff the fire brigade. Specifically, the licensee required actions from all operators other than the two waste control operators during a simultaneous alternative shutdown of both units. This left the two waste control operators and the security officer as the only assigned fire brigade members that could respond to a potential control room fire. The team reviewed the fire protection licensing basis. Since the control rooms were located in the same fire area, the team concluded that the licensee must be able to perform a simultaneous alternative shutdown of both units and staff the fire brigade. The team noted that the licensee did not have an exemption from this requirement. The licensee identified this non-compliance in 2006 and documented this issue in Condition Report CR-ANO-C-2006-00048, Corrective Action 36. In response to this concern, the licensee performed a risk evaluation but failed to initiate any corrective actions or compensatory measures. In 2007 and 2012, the licensee subsequently added the auxiliary operator and alternate shutdown operator positions, respectively, for an alternative shutdown of Unit 2. During each addition, the licensee failed to ensure the adequate staffing for operators to perform a simultaneous alternative shutdown of both units and staff the fire brigade. The licensee determined that alternative shutdown of both units would not be required since a fire in one control room would not be capable of causing circuit damage in equipment located in the other control room. The licensee developed detailed fire models to demonstrate this position as part of the transition to NFPA-805. The licensees License Amendment Request for Unit 2, dated March 27, 2012 (ML12087A113) has been submitted to the NRC and is under review by the NRC staff. The result of the NRC staff review of this analysis will be required to determine if this issue is more than minor. This issue is being treated as an unresolved item: URI 05000313;05000368/2013009-002, Failure to Maintain Adequate Staffing for Operators to Perform a Simultaneous Alternative Shutdown of Both Units and Staff the Fire Brigade.
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