Semantic search

Jump to navigation Jump to search
 QuarterSiteTitleDescription
05000366/FIN-2018003-012018Q3HatchInoperability of 2A EDG Due to Inadequate Acceptance Criteria for Determining Cleaning Requirements of Emergency Diesel Generator Day TanksThe inspectors documented a Green, self-revealing, non-cited violation of Unit 2 Technical Specification 5.4.1(a) for the licensees failure to incorporate preventative maintenance criteria for Emergency Diesel Generator (EDG) day tanks as recommended by Regulatory Guide (RG) 1.33, 9.a. Specifically, procedure 52SV-R43-001-0, Diesel, Alternator, and Accessories Inspection, Ver. 30.4, did not contain deterministic criteria in the visual inspection of the fuel filters to initiate the cleaning of the EDG day tanks and thus prevent EDG inoperability. The EDG day tanks had never been inspected and cleaned.
05000321/FIN-2018002-012018Q2HatchEnforcement Action (EA)-18-100: Unanalyzed Conditions for a Postulated Fire Discovered During NFPA 805 TransitionOn April 3, 2017, the licensee submitted Licensee Event Report (LER) 05000321, 366/2017-001-00: Unanalyzed Conditions for a Postulated Fire Discovered During NFPA 805 Transition documenting the discovery of a condition of non-compliance with the sites fire protection program (FPP). In preparation for transiting the fire protection licensing basis from 10 CFR 50.48(b) (Appendix R) to 10 CFR 50.48(c) (NFPA 805), a weak-link and operator manual action analysis was completed for Information Notice 92-18 type hot shorts on motor operated valves (MOV). The licensees examination of their Appendix R Safe Shutdown Analysis identified circuit configurations in multiple fire areas where an Appendix R postulated fire could impact the ability to achieve safe shutdown conditions. The licensee failed to protect MOV cables associated with the RHR and RCIC emergency cooling systems in fire areas 0024 (Main Control Room), 1203F (Unit 1 Reactor Building), 1205F (Unit 1 Reactor Building), and 2203F (Unit 2 Reactor Building). Specifically, the licensee failed to ensure that fire induced cable impacts cannot bypass the limit and torque switches and result in physical damage to the MOVs, thus preventing the MOVs from being operated from the Main Control Room, Remote Shutdown Panel, or locally. This condition could prevent operators from achieving and maintaining safe shutdown (SSD) of the plant in the case of a postulated fire. A licensee-identified non-compliance with 10 CFR Part 50, Appendix R, Section III.G.2, was identified for the licensees failure to protect one of the redundant trains of equipment needed to achieve post-fire SSD from fire damage. Specifically, the licensee failed to use one of the means described in Appendix R, Section III.G.2.a, b, or c to ensure that one of the redundant trains of equipment necessary to achieve and maintain hot shutdown conditions was protected from fire damage. The inspectors performed a detailed review of the information and documents related to the LER and discussed the condition with the licensee to assess the adequacy of the licensees compensatory measures and corrective actions. Corrective Action(s): Hourly fire watches and Fire Action Statements were initiated to address the postulated condition for the identified MOVs. Additionally, the licensee committed to completing physical plant modifications to the impacted MOVs during the next Unit 1 and Unit 2 plant refueling outages to rectify the issue of potential spurious operation of the associated MOVs associated with this LER. Corrective Action Reference(s): The licensee entered this issue into their Corrective Action Program (CAP) as condition reports (CRs) 10326399, 10326401, 10326402, 10326404, and 10326405. Enforcement: Violation: 10 CFR Part 50.48(b)(1) requires that all nuclear power plants licensed to operate prior to January 1, 1979, must satisfy the applicable requirements of 10 CFR Part 50, Appendix R, Section III.G. 10 CFR 50, Appendix R, Section III.G.2, states, in part, that where cables or equipment, that could prevent operation or cause mal-operation due to hot shorts, open circuits, or shorts to ground, of redundant trains of systems necessary to achieve and maintain hot shutdown conditions are located within the same fire area outside of primary containment, one of the following means of ensuring that one of the redundant trains is free of fire damage shall be provided: (a) separation of cables and equipment by a fire barrier having a 3-hour rating, (b) separation of cables and equipment by a horizontal distance of more than 20 feet with no intervening combustibles or fire hazards and with fire detectors and an automatic fire suppression system in the fire area, or (c) enclosure of cables and equipment in a fire barrier having a 1-hour rating and with fire detectors and an automatic fire suppression system in the fire area. Contrary to the above, the licensee failed to use one of the means described in Appendix R, Section III.G.2.a, b, or c to ensure that one of the redundant trains of equipment necessary to achieve and maintain hot shutdown conditions was protected from fire damage. Specifically from October 1974 to April 2017, the licensee had not met the requirements of 10 CFR Part 50.48(b) to identify and protect cabling of 51 Unit 1 and Unit 2 RHR and RCIC emergency cooling system MOVs in fire areas 0024 (Main Control Room), 1203F (Unit 1 Reactor Building), 1205F (Unit 1 Reactor Building), and 2203F (Unit 2 Reactor Building). On April 3, 2017, the licensee identified the failure to protect equipment that was required to mitigate fire events and determined that fire damage could cause mal-operation of the affected MOVs, potentially leading to fire induced cable impacts which bypass the limit and torque switches and result in physical damage to the MOVs, thus preventing the MOVs from being operated from the Main Control Room, Remote Shutdown Panel, or locally. A fire-induced failure could have caused the loss of the required Safe Shutdown components. Severity/Significance: Failure to protect one train of cables and equipment necessary to achieve post-fire SSD from fire damage for fire areas designated in the Fire Protection Program (FPP) as meeting Appendix R, Section III.G.2, was a performance deficiency. This finding was more than minor because it was associated with the reactor safety mitigating system cornerstone attribute of protection against external events (i.e., fire). Specifically, failure to protect safe shutdown cables and equipment from fire damage negatively affected the reactor safety mitigating systems cornerstone objective of ensuring the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences. Because this issue relates to fire protection and this non-compliance was identified as a part of the sites transition to NFPA 805, this issue is being dispositioned in accordance with Section 9.1, Enforcement Discretion for Certain Fire Protection Issues (10 CFR 50.48) of the NRC Enforcement Policy. The significance of this licensee-identified non-compliance with 10 CFR Part 50, Appendix R, Section III.G.2, was determined by the results of the IMC 0609, Appendix F, Fire Protection Significance Determination Process, Phase III Quantitative Screening Approach. The quantitative screening approach performed by a Region II Senior Risk Analyst resulted in a calculated delta core damage frequency (CDF) of less than 1E-04, which screens this noncompliance to less-than-red significance. Additionally, in order to verify that this noncompliance was not associated with a finding of high safety significance (Red), inspectors reviewed qualitative and quantitative risk analyses performed by the licensee. These risk evaluations took ignition source and target information from the ongoing HNP fire PRA to demonstrate that the significance of the non-compliances were less-thanthan 1E-4/year). The inspectors also performed walk-downs to verify key assumptions were applicable. Based on the ignition frequency of fire sources in the affected areas, inspectors determined that the significance of this non-compliance was less-than-red. The inspectors also noted that the values in the licensees quantitative analysis were conservative, in that they used screening values instead of more detailed values. This provided additional confidence that this non-compliance was not associated with a finding of high safety significance (Red). The inspectors determined that no cross cutting aspect was applicable to this performance deficiency because this finding was not indicative of current licensee performance. Basis for Discretion: The NRC exercised enforcement discretion in accordance with Enforcement Policy, Section 9.1, Enforcement Discretion for Certain Fire Protection Issues (10 CFR 50.48), a Confirmatory Order (ML16223A467) which extended the period for discretion, and Inspection Manual Chapter 0305. On April 4, 2018 (ML18096A955), the licensee submitted a license amendment request to adopt NFPA 805 and change their fire protection licensing bases to comply with 10 CFR 50.48(c). The inspectors reached this conclusion due to the fact that this issue was licensee-identified and will be addressed during the licensees transition to NFPA 805, it was entered into the licensees corrective action program, immediate corrective action and compensatory measures were taken, it was not likely to have been previously identified by routine licensee efforts, it was not willful, and it was not associated with a finding of high safety significance (Red).
05000321/FIN-2018001-022018Q1HatchLicensee-Identified ViolationThis violation of very low safety significant was identified by the licensee and has been entered into the licensee corrective action program and is being treated as a Non-Cited Violation, consistent with Section 2.3.2 of the Enforcement Policy. Violation: Hatch Nuclear Plant Technical Specification (TS) 5.7.2 states in part, areas with radiation levels greater than 1000 mRem/hr, measured at 30 cm from the radiation source or from any surface the radiation penetrates, but less than 500 Rads in 1 hour measured at 1 meter from the radiation source or from any surface that the radiation penetrates, shall be provided with locked or continuously guarded doors to prevent unauthorized entry.Contrary to the above, February 6, 2018, the licensee identified dose rates of 72 Rem/hr on contact, and 3.9 Rem/hr at 30 cm on the U-1 bottom head drain valve located in the 127 foot elevation of the Subpile room, in the Unit 1 Drywell. For approximately 4 hours, the entrance to the room was not locked or continuously guarded to prevent unauthorized entry as required by TS 5.7.2. Significance/Severity: The finding was of very low safety significance (Green) because it was not an as low as reasonably achievable (ALARA) planning issue, there was no overexposure nor potential for an overexposure, and the licensees ability to assess dose was not compromised.Corrective Action Reference(s):The licensee identified and documented the failure to control access to the Lock High Radiation Area (LHRA) in Condition Report 10458608.
05000321/FIN-2018001-012018Q1HatchFailure to comply with Type B shipping container Certificate of Compliance (CoC) requirements.An NRC Identified Green NCV of 10 Code of Federal Regulations (CFR)71.17, General license: NRC-approved package, was identified for the licensees failure to comply with the Type B shipping container Certificate of Compliance (CoC) requirements. 10 CFR 71.17(c)(2)states, in part, that a holder of a General license to utilize an NRC-approved package shall comply with the terms and conditions of the license, certificate, or other approval, as applicable, and the applicable requirements of subparts A, G, and H of this part. Specifically, on several occasions the licensee placed in transit Type B containers which did not pass the CoC leak test requirement(s).
05000321/FIN-2017004-022017Q4HatchLack of Requirement for Engineering Evaluation of Scaffolding Near Safety-related PipingAn NRC-identified Green NCV of 10 CFR 50, Appendix B, Criterion V, Instructions, Procedures, and Drawings, was identified when the licensee failed to ensure engineering evaluations were performed when scaffolding was constructed within 2 inches of safety-related piping. The failure to ensure procedure NMP-MA-010, Erecting, Modifying, and Disassembling Scaffolding, required engineering evaluations when scaffolding was constructed within 2 inches of safety-related piping was a performance deficiency. The violation was entered into the licensees corrective action program as CR 10420643.The performance deficiency was more-than-minor because the licensees procedure, as written, would never require an engineering evaluation of any safety-related piping based on the exceptions granted in the procedure. The inspectors determined that the finding was of very low safety significance (Green) because the finding did not represent an actual open pathway in the physical integrity of reactor containment. The inspectors determined that the finding did not have an associated cross-cutting aspect because the discrepancy was introduced during a transition to a fleet standardized procedure, which occurred more than three years ago and was therefore not reflective of current licensee performance.
05000280/FIN-2017004-022017Q4SurryFailure to Identify a Non-Functional Flood Control BarrierAn NRC-identified Green NCV of 10 CFR Part 50, Appendix B, Criterion XVI was identified for the licensees fa ilure to identify a condition adverse to quality related to the material condition of the machinery equipment room (MER) 5 flood dike. Specifically, the inspectors identified on November 13, 2017, several bolts on the connecting plates of the dike that were visually not flush, and found to be loose. As a result, the licensee declared the MER 5 flood dike non-functional and the D and E main control room (MCR) chillers inoperable. This issue was documented in the licensees CAP as CR 1083839. As immediate corrective action, the licensee torqued all structural bolts to 12 ft-lbs and floor anchor nuts to 55 ft-lbs per WO 38103865619.The inspectors determined that failure to identify a condition adverse to quality associated with the material condition of the MER 5 flood dike was a PD. Specifically, the inspectors identified on November 13, 2017, several loose bolts on the connecting plates of the MER 5 flood dike. As a result, the licensee declared the MER-5 flood dike non-functional and the D and E main control room (MCR) chillers inoperable. The inspectors determined that the PD was more than minor because it was associated with the protection against external factors attribute of the Mitigating Systems Cornerstone and adversely affected the cornerstone objective to ensure the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences. Specifically, the licensee failed to ensure that WO 38103734871 and drawing 11548-FC-6L had fastener torque specifications and a re-torque requirement for the MER 5 dike after it was re-assembled; and failed to identify a non-functional MER 5 flood dike. Using IMC 0609.04, Initial Characterization of Findings, Table 2, dated June 19, 2012; the finding was determined to affect the Mitigating Systems Cornerstone. The inspectors screened the finding using IMC0609, Appendix A, SDP for Findings at-Power dated June 19, 2012, the inspectors determined that a detailed risk evaluation was required. A detailed risk evaluation of the PD was performed in accordance with IMC 0609 Appendix A by a regional Senior ReactorAnalyst (SRA) using input from the licensees full scope Probabilistic Risk Assessment model. The result of the bounding analysis was an increase in core damage frequency due to the performance deficiency of <1E-6/year, a Green finding of very low safety significance.This finding has a cross-cutting aspect in the evaluation component of the problem identification and resolution area, P.2, because the organization did not thoroughly evaluate issues to ensure that resolutions address causes and extent of conditions commensurate with their safety significance. Specifically, ETE SU-2017-0044, written for the May, 2017, non-functional MER 5 flood dike, did not thoroughly evaluate gasket type and bolting torque, when evaluating if epoxy was required for the assembly of the MER 5 flood dike.
05000321/FIN-2017004-032017Q4HatchA violation of Technical Specification (TS) 3.4.3 was identified because two of eleven safety relief valves were found to be outside the tolerance allowed by TS Surveillance Requirement (SR) 3.4.3.1 for the opening set-point pressure.Description: During the February 2017 Unit 2 refueling outage, all eleven 3-stage safety relief valves (SRVs) were removed and replaced. The SRVs were Target Rock model 0867F, a 3-stage valve design which was in its first use on Unit 2. This design was adopted as a corrective action to address corrosion bonding experienced by 2-stage SRV model 7687F valves which were previously in use at Hatch. "As-found" testing results indicated two of the eleven SRVs had experienced a setpoint drift during the previous operating cycle which resulted in their failure to meet the Technical Specification (TS) opening setpoint pressure as required by TS Surveillance Requirement (SR) 3.4.3.1. The SRV pilot valves were disassembled and inspected to determine the reason for the drift. The licensee determined that the abutment gap closed pre-maturely most likely due to loose manufacturing tolerances. For the 3-stage design, the pilot disc seating stresses should increase proportionally as reactor pressure increases to where a mechanical gap within the valve stem mechanism, referred to as the abutment gap, is closed. Additional pressure increases will cause the valve stem mechanism to reduce the disc seat pressure until the valve eventually opens. This same cause was previously identified in 2016 (CAR 264544) after two of eleven SRVs removed from Unit 1 also experienced setpoint drift. Because the Unit 2 valves were already installed when the cause was initially identified, there was no opportunity for the licensee to take corrective actions for the valves that are the subject of this LER. Additionally, there were no symptoms available to operators or maintenance personnel to indicate the potential for the set point drift prior to post-service testing. As a corrective action, when the eleven valves were removed for post-service testing, the licensee installed eleven refurbished pilot valves that underwent the corrective actions identified by CAR 264544 which included the vendors usage of revised tolerances.Enforcement: Hatch Unit 2 TS limiting condition for operation 3.4.3, Safety/Relief Valves, required 10 of 11 SRVs be operable in MODES 1, 2 and 3. With two or more SRVs inoperable, the required TS action must be taken by the applicable completion time. Contrary to the above, Unit 2 operated from the initiation of the degraded condition until February 6, 2017, with two SRVs inoperable. The inspectors concluded that the violation would normally be characterized as a Severity Level IV violation because it was of very low safety significance (Green). However, the NRC is exercising enforcement discretion (EA-18-006) in accordance with Section 3.10 of the Enforcement Policy because the violation was not associated with a licensee performance deficiency. This issue was documented in the licensees corrective action program as CR 10382586.
05000366/FIN-2017004-012017Q4HatchContinuous Fire Watch or Compensatory Measures Not Established per FHAAn NRC-identified non-cited violation (NCV) of Unit 2 License condition 2.C.(3)(a) Fire Protection was identified when on October 17, 2017, the licensee failed to establish a continuous fire watch or alternative compensatory measures required by Hatchs Fire Hazards Analysis (FHA), Appendix B, while the carbon dioxide fire protection system was nonfunctional during a routine maintenance outage for the 2C emergency diesel generator. Failure to establish a continuous fire watch or alternative compensatory actions as required by Hatchs Fire Hazards Analysis, Appendix B, when the low pressure carbon dioxide storage system became inoperable on October 17, 2017, was a performance deficiency. The licensee restored compliance on October 25, 2017, when the double fire door was shut, restoring functionality of the carbon dioxide system. The licensee entered this issue into the corrective action program as Condition Report (CR) 10423361.This performance deficiency was more-than-minor because the failure to establish a continuous fire watch or alternative compensatory measures adversely affected the reliability of the carbon dioxide system and/or compensatory measures. The finding screened to green because the alternate train of safe shutdown remained operable. The inspectors determined this performance deficiency had a cross cutting aspect in the Human Performance Area Training attribute because of the observed weakness in the application of FHA applicability statements. (H.9)
05000280/FIN-2017004-012017Q4SurryInadequate Instructions for Corrective Maintenance on Unit 1 C RC Hot Leg Sample ValveA self-revealing, non-cited violation (NCV) of Surry Technical Specification (TS) 6.4.A.7 was identified for the failure to have detailed written procedures with appropriate instructions in design change packages (DCPs) 78-001, 80-007, and 84-369 when replacing 1-SS-HCV-101C, the Unit 1 C reactor coolant (RC) hot leg sample valve. This resulted in 1-SS-HCV-101C developing a through-wall leak on the tube to valve socket weld. Additionally, due to the reactor coolant system (RCS) boundary leakage, Unit 1 required an unplanned shutdown per TS 3.1.C.3 on August 9, 2017. This issue was documented in the licensees corrective action program (CAP) as condition report (CR) 1075404. During the shutdown, the licensee made an American Society of Mechanical Engineering (ASME) code repair by cutting and capping the tubing to stop the leak. 1-SS-HCV-101C will be restored to normal system configuration during the next refueling outage in April 2018.The inspectors determined that the failure of the licensee to have the instructions necessary to properly install the C RCS loop hot leg sample valve and tubing as required by Surry procedure SUI-0001 was a performance deficiency (PD). Specifically, DCPs 78-001,80-007, and 84-369 did not have instructions necessary to ensure the 1-SS-HCV-101C and the associated tubing was properly mounted to absorb the stresses applied to the valve and tubing during normal operation of the valve. As a consequence of the insufficient supports, 1-SS-HCV-101C experienced a through-wall leak on a socket weld on August 9, 2017, which subsequently required an unplanned shutdown of Unit 1. Using Inspection Manual Chapter (IMC) 0612, Appendix B, Issue Screening, dated September 7, 2012, the inspectors determined that the PD was more than minor because it was associated with the procedural quality attribute of the Initiating Events Cornerstone and adversely affected the cornerstone objective to limit the likelihood of events that upset stability and challenge critical safety functions during shutdown as well as power operations. Using IMC 0609.04, Initial Characterization of Findings, Table 2, dated October 7, 2016; the finding was determined to adversely affect the Initiating Events Cornerstone. The inspectors screened the finding using IMC 0609, Appendix A, Significance Determination Process (SDP) for Findings at-Power dated June 19, 2012, and determined that it screened as Green because the deficiency did not cause a loss of mitigation equipment relied upon to transition the plant to a stable shutdown condition. This finding did not have a cross-cutting aspect because it is not considered current licensee performance.
05000280/FIN-2017002-012017Q2SurryFailure to Have Work Instructions Impacting MER 5 Flood BarrierAn NRC-identified, NCV of Surry Technical Specification (TS) 6.4.A.7 was identified because the mechanical equipment room (MER) 5 flood dike was not installed in accordance with the manufacturers installation procedures after it was removed for maintenance. Specifically, work order (WO) 38103734871, procedure GMP-013, Removal and Installation of Flood Protection Dikes and Secondary Flood Shields and Placing MER 3 in Extended Access, Revision 22, and drawing 11548-FC-6L, Flood Protection Dike Details MER 5 Turbine Building Unit 2, Revision 0, did not provide instructions, procedures, or drawing specifics that took into account the manufacturer instructions of using epoxy to ensure a water tight seal; and failed to use the materials as listed in drawing 11548-FC-6L during the reinstallation of MER 5 flood dike. The issue was documented in the licensees corrective action program (CAP) as condition reports (CR) 1068357, 1068357, and 1068528.The inspectors determined that not having and following work instructions and drawings appropriate to the reinstallation of MER 5 flood dike is a performance deficiency (PD). This PD is more than minor because it is associated with the protection against external factors attribute of the Mitigating Systems Cornerstone and adversely affected the cornerstone objective to ensure the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences. Specifically, on May 2, 2017, the licensee failed to ensure WO 38103734871, procedure GMP-013, and drawing 11548-FC-6L had detailed manufacturer instructions to use epoxy to ensure a water tight seal and failed to use the materials as listed in drawing 11548-FC-6L. Using IMC 0609, Appendix A, The Significance Determination Process for Findings At-Power,dated June 19, 2012, and IMC 0609, Appendix A, Exhibit 2, Mitigating Systems Screening Questions, the inspectors determined that the finding was of very low safety significance (Green) because the finding is a deficiency affecting the design or qualification of a mitigating structure, system, or component (SSC), in this case the main control room (MCR) chillers in MER 5, in which the SSC in question maintained its operability. This finding has a cross-cutting aspect in the area of human performance associated with teamwork, in that, individuals and work groups failed to communicate and coordinate their activities within and across organizational boundaries to ensure nuclear safety is maintained. Specifically, while preparing for and performing MER 5 flood dike reinstallation using WO 38103734871, procedure GMP-013, and drawing 11548-FC-6L, the licensee utilized a new foam material, but the differentdepartments in the organization (specifically Supply, Engineering, and Maintenance) failed to work together to evaluate the supplied manufacturer material and any specific requirements needed for installation (H.4)
05000280/FIN-2017008-012017Q1SurryFailure to verify or check the adequacy of a design change in the Recirculation Spray Service Water Valve Pits.Green: The inspectors identified a non-cited violation of Title 10 CFR Part 50, Appendix B, Criterion III, Design Control, for the licensees failure to verify or check the adequacy of the design of bulkheads in the recirculation spray service water motor operated valve pits. Specifically, the design allowed for unsealed penetrations in bulkheads and the licensee failed to demonstrate that the unsealed penetrations would not adversely affect the ability of the bulkheads to provide adequate train separation during a postulated pipe rupture. The licensee entered the issue into the CAP as Condition Report (CR) 1060189 and sealed the penetrations. This performance deficiency was determined to be more than minor because it was associated with the design control attribute of the Mitigating Systems Cornerstone and it adversely affected the cornerstone objective to ensure the capability of systems that respond to initiating events to prevent undesirable consequences. Specifically, the 3 capability to maintain train separation between the Recirculation Spray Service Water header motor operated valves was adversely affected due to the presence of degraded penetrations through the flood barriers. The team determined the finding to be of very low safety significance (Green) because the finding was a deficiency affecting the design of a mitigating structure, system, or component (SSC), and the SSC maintained its operability or functionality. This finding was not assigned a cross-cutting aspect because the issue did not reflect current licensee performance.
05000400/FIN-2017001-012017Q1HarrisLicensee-Identified ViolationThe following violation of very low safety significance (Green) was identified by the licensee and is a violation of NRC requirements which meet the criteria of the NRC Enforcement Policy, for being dispositioned as a NCV. Appendix B to 10 CFR Part 50, Criterion V, Instructions, Procedures, and Drawings, required in part, that activities affecting quality shall be prescribed by documented instructions, procedures, or drawings, of a type appropriate to the circumstances and shall be accomplished in accordance with these instructions, procedures, or drawings. Contrary to the above, on March 22, 2017, the licensee identified that an environmental protection feature, 1EE-E668 (FHB 261 floor hatch), was removed from service withou stationing a dedicated attendant as required by licensee procedure AP-046, Control of Environmental Protective Features. The floor plug was removed for two days (March 20-22, 2017) to support maintenance activities before the condition was identified by licensee operations personnel while performing rounds. Using IMC 0609, Appendix A, Significance Determination Process for Findings At-Power, inspectors determined that this violation was of very low safety significance (Green) because the finding did not impact the frequency of a fire or internal flooding initiating event and all structures, systems, and components remained capable of performing there intended safety functions. This issue was documented in the licensees CAP as AR 20110596.
05000280/FIN-2017001-012017Q1SurryFailure to Maintain Requalification Examination IntegrityGreen . An NRC- identified NCV of 10 CFR 55.49, Integrity of examinations and tests, was identified for the licensees failure to adhere to the requirements of TR -AA -730, Licensed Operator Biennial and Annual Operating Requalification Exam Process, Revision 9. TR -AA- 730 was the procedure that the licensee used to implement industry standard ACAD 07- 001, Guidelines for the Continuing Training of Licensed Personnel. ACAD 07 -001 is a methodology which can be used to fulfill 10 CFR 55.59(c), Requalification program requirements and 10 CFR 55.4, Systems approach to training (SAT). This violation has been entered into the licensees corrective action program (CAP) as condition report (CR) 1058649. T he performance deficiency was determined to be more than minor because, if left uncorrected, it had the potential to lead to a more significant safety concern with the administration of the operating exams. The inspectors assessed the significance in accordance with Manual Chapter 0609, Significance Determination Process, Appendix I, Licensed Operator Requalification Significance Determination Process (SDP). The finding was determined to be of very low safety significance (Green) because there was no evidence that a licensed operator had actually gained an unfair advantage on an examination required by 10 CFR 55.59. The finding was directly related to the cross -cutting aspect of Complacency in the cross -cutting area of Human Performance because the training staff was aware of the TR -AA -730 requirements for annual operating exam scenario overlap, but justified an alternative method of exam security that was used in the past. (H.12)
05000280/FIN-2016004-012016Q4SurryChange of Surveillance Frequency Caused the Charging Service Water Header to Become Biologically FouledA self-revealing NCV of 10 CFR 50, Appendix B, Criterion XVI was identified because the surveillance procedure frequency used to flush the service water (SW) piping in Mechanical Equipment Room (MER)-3 and MER-4 was changed from two weeks to four weeks without sufficiently considering the effects of river conditions on biological growth and without getting management permission to change the periodicity. As a result of the periodicity change, the B charging (CH) and main control room (MCR) SW header became blocked with biological growth and was declared inoperable on September 22, 2016, during the performance of 0-OSP-VS-012, High Flow Flush of SW Strainers and Piping in MER 3 and MER 4. As immediate corrective action, the licensee cleaned the clogged SW strainer and completed the backflushing of the SW header. The SW flushing periodicity was restored to a two week frequency to be seasonally and risk assessed and reduced as heavy fouling season ends. This issue was documented in the licensees corrective action program (CAP) as CR 1048251. The inspectors reviewed Inspection Manual Chapter (IMC) 0612, Appendix B, Issue Screening, dated September 7, 2012, and determined the performance deficiency (PD) was more than minor because it was associated with the equipment performance attribute of the Mitigating Systems Cornerstone, and it adversely affected the cornerstone objective to ensure the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences. Using IMC 0609.04, Initial Characterization of Findings, Table 2, dated June 19, 2012, the finding was determined to affect the Mitigating Systems Cornerstone. The inspectors screened the finding using IMC 0609, Appendix A, Significance Determination Process (SDP) for Findings at-Power, dated June 19, 2012, and determined that it screened as Green because the deficiency did not affect the design or qualification of the charging pump service water pump system and it did not represent a loss of system safety function. This finding has a cross-cutting aspect in conservative bias aspect of the human performance area, H.14, because the licensee did not use decision making-practices that emphasize prudent choices over those that are simply allowed.
05000400/FIN-2016004-012016Q4HarrisLicensee-Identified ViolationTS limiting condition for operation (LCO) 3.3.3.6, Action C, Accident Monitoring Instrumentation, states in part that with the number of operable accident monitoring instrumentation channels for the radiation monitor(s), less than the minimum channels operable, initiate the preplanned alternate method of monitoring the appropriate parameter(s), within 72 hours, and either restore the inoperable channel(s) to operable status within 7 days or prepare and submit a Special Report to the Commission, pursuant to Specification 6.9.2, within the next 14 days. TS Table 3.3-10 indicates that a minimum of one channel of the Containment High Range Radiation Monitors (CHRRMs) is required to be operable. Contrary to the above, the licensee identified that they failed to identify the inoperability of the CHRRMs and take the required actions of LCO 3.3.3.6, Action C, from 1998 until an operability determination was completed in September 2016. Using IMC 0609, Appendix B, Emergency Preparedness Significance Determination Process, inspectors determined that this violation was of very low safety significance (Green) because the finding was a failure to comply with a non-risk significant planning standard and no planning standard function failure occurred since other parameters could be used to validate the indications from the CHRRMs. This issue was documented in the licensees CAP as AR 2063783.
05000281/FIN-2016004-022016Q4SurryInadequate Design Change Post Maintenance Testing Causes Water Intrusion into Station Service Transformer and a Reactor TripA self-revealing finding was identified because the test requirements section of the station service transformer (SST) design change (DC) was not comprehensive in that it did not test that the isolated phase bus ducting terminal boxes were constructed to prevent water intrusion into the boxes. This was discovered during a significant rainfall event partially caused by Hurricane Matthew, which filled up the A SST terminal box with water and eventually shorted the A phase of the main generator causing a Unit 2 main generator, main turbine, and subsequent reactor trip on October 9, 2016. As corrective action, sealant was applied to the SST terminal boxes on all seams and bolt holes; and weep holes with drain assemblies were installed on each box. This issue was documented in the licensees CAP as CR 1049987. The inspectors reviewed Inspection Manual Chapter (IMC) 0612, Appendix B, Issue Screening, dated September 7, 2012, and determined the PD was more than minor because it was associated with the design control attribute of the Initiating Events Cornerstone, and it 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. Using IMC 0609.04, Initial Characterization of Findings, Table 2, dated October 7, 2016, the finding was determined to affect the Initiating Events Cornerstone. The inspectors screened the finding using Manual Chapter 0609, Appendix A, SDP for Findings at-Power, dated June 19, 2012, and determined that it screened as Green because although the deficiency did cause a reactor trip, it did not cause a loss of mitigation equipment relied upon to transition the plant from the onset of the trip to a stable shutdown condition. This finding has a cross-cutting aspect in the Operating Experience aspect of the Problem Identification and Resolution area, P.5, because the licensee did not evaluate and implement relevant external operating experience.
05000400/FIN-2016003-012016Q3HarrisSubsequent Loss of Safety-Related Chilled Water System Results in a Loss of Safety FunctionThe inspectors opened a URI to facilitate prompt tracking, documentation, and closure of inspection, verification, and resolution activities, associated with the A ESCW chiller failures. On July 15, 2016, the A ESCW chiller tripped on low oil pressure. Licensee investigation identified that oil was leaking from the threaded portion of a brass fitting located between a pressure switch and needle valve associated with PDS-01CY-9428ASA-HI. Upon removal, it was observed that significant radial cracking occurred in the threaded portion of the brass fitting. A like-for-like replacement was installed and the A ESCW chiller was returned to service. One week later, on July 22, 2016, the A ESCW chiller tripped again on low oil pressure. The investigation revealed that the same brass fitting had failed and the A ESCW chiller could not meet its mission time of 30 days of continuous operation in the event of a loss of cooling accident. During this 7-day period, the B ESCW chiller was inoperable for a period of time, which means the ESCW system would not have been able to meet its safety function. The licensees investigation into the cause of the subsequent failure is ongoing. A URI is being opened to determine whether the subsequent failure of the brass fitting was reasonably within the licensees ability to predict and therefore a performance deficiency. This issue is being tracked as URI 05000400/2016003-01, Subsequent Loss of Safety-Related Chilled Water System Results in a Loss of Safety Function.
05000280/FIN-2016003-012016Q3SurryLicensee-Identified ViolationThe licensee identified a non-cited violation of very low safety significance of 10 CFR 72.150,Instructions, Procedures, and Drawings. Title 10 CFR 72.150, Instructions, Procedures, and Drawings, requires, in part, that activities affecting quality be prescribed by documented procedures of a type appropriate to the circumstances and be accomplished in accordance with these procedures. The licensee established PBF5101, Fuel/Insert/Component Movement Authorization, Revision 17, as the implementing procedure for dry fuel storage fuel loading, an activity affecting quality. Procedure PBF5101 contains instructions for fuel handlers to move specific fuel assemblies from specific spent fuel pool locations into specific dry shielded canisters (DSCs) and DSC locations. Contrary to the above, on July 18, 2016, the licensee failed to follow PBF5101. Specifically, the licensee was utilizing a PBF5101 labeled for DSC25 during the loading of DSC24. This resulted in three fuel assemblies being incorrectly loaded into DSC24. The license entered the issue into its corrective action program under AR 02144237, dated July 18, 2016, and initiated actions to perform an apparent causal evaluation. The inspectors identified that DSC24 and DSC25 have identical design characteristics and therefore there was no actual safety significance to this event. Consistent with the guidance in Section 2.2 of the NRC Enforcement Policy, ISFSIs are not subject to the Significance Determination Process and, thus, traditional enforcement will be used for this issue. However, the inspectors determined that the violation significance could be informed by the significance determination process as no similar violations existed in the enforcement policy violations examples. The inspectors determined that the violation could be evaluated using Inspection Manual Chapter 0609, Attachment 04, Initial Characterization of Findings, and Appendix A, Exhibit 3, Barrier Integrity Screening Questions. This resulted in the violation screening as Severity Level IV.
05000335/FIN-2016007-012016Q2Saint LucieIntake Cooling Water Pump House Transient Combustible Fire Loading CalculationThe inspectors identified an unresolved item (URI) associated with the transient combustible heat load calculation for both Units ICW pump houses and the basis for exclusion of treated or fire retardant wood. The URI is being opened to review the licensees evaluation and determine if a performance deficiency exist. Three ICW pumps and motors are located in each house. Each pump motor is 600 horsepower. During a walkdown of both units ICW pump houses, inspectors noted that the scaffolding around the ICW pumps consisted of metal and wood planks. The inspectors determined that the wood was not included in heat load calculation for the respective pump houses. The licensee stated that the wood was treated or fire retardant and did not need to be included in the sites transient combustible heat load calculations. The inspectors questioned the licensee on the basis for not including the treated wood in the transient combustible heat load calculation. The licensee entered this issue into the CAP as 2133079 and 2134308, and initiated corrective actions to evaluate the basis for not performing a combustible heat loading calculation for fire retardant wood. The licensee also took corrective actions to replace the wood with a non-combustible material. Additional inspection time is required to review the licensees evaluation and determine if a performance deficiency exist. This issue will be tracked as URI 05000335,389 / 2016007-01, Intake Cooling Water Pump House Transient Combustible Fire Loading Calculation.
05000280/FIN-2016001-012016Q1SurryFailure to Perform a 10 CFR 50.59 Evaluation for Blocking Ventilation to Main Steam Valve HousesAn NRC-identified finding of very low safety significance and an associated Severity Level IV NCV of 10 CFR 50.59, Changes, Tests, and Experiments, was identified when the licensee failed to perform and maintain a written evaluation to demonstrate that a procedure change did not require a license amendment. Specifically, the licensee implemented a change to procedure 0-OP-ZZ-021, Severe Weather Preparation, Revision 12, to allow installation of tarpaulins over the main steam valve house (MSVH) ventilation louvers thereby changing the Updated Final Safety Analysis Report (UFSAR) facility design without maintaining supporting calculations. The licensees failure to perform a 10 CFR 50.59 evaluation was a performance deficiency (PD). The inspectors determined that the PD was more than minor because it was associated with the design control attribute of the Mitigating Systems 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 change allowed the ventilation of the MSVH to be blocked and the lack of engineering calculations resulted in a condition where there was a reasonable doubt about the operability of the auxiliary feedwater (AFW) pumps for their required mission time. Using Manual Chapter 0609.04, Initial Characterization of Findings, Table 2, dated June 19, 2012; the finding was determined to adversely affect the Mitigating Systems Cornerstone. The inspectors screened the finding using Inspection Manual Chapter (IMC) 0609, Appendix A, Significance Determination Process (SDP) for Findings at-Power, dated June 19, 2012, and determined that it screened as Green because the PD did not affect the design or qualification of the AFW system and it did not represent an actual loss of system safety function. Using IMC 0310, Aspects within the Cross-Cutting Areas, dated December 4, 2014, the inspectors determined that the finding had a cross-cutting aspect in the procedure adherence component of the human performance area, H.8, because the licensee failed to follow processes, procedures and work instructions for the 50.59 applicability review when changing the severe weather preparation procedure. Additionally, the failure to perform a 10 CFR 50.59 evaluation was determined to be more-than-minor in accordance with the guidance in the NRC Enforcement Manual for traditional enforcement violations, because the MSVH louvers were actually covered and there was a reasonable likelihood that the lack of MSVH ventilation could affect the operability of the AFW pumps for their required mission time. The failure constitutes a violation of 10 CFR 50.59, which impacts the regulatory process and therefore, was evaluated through the traditional enforcement process. The SDP, which was used to evaluate this performance deficiency, does not specifically consider the impact on the regulatory process. Thus, although related to a common regulatory concern, it is necessary to address both the violation and finding using different processes to correctly reflect both the regulatory importance of the violation and the safety significance of the associated performance deficiency.
05000281/FIN-2015004-012015Q4SurryInsufficient Gasket Crush on Pressurizer Spray Valve Body to Bonnet JointA self-revealing, Green non-cited violation (NCV) of Surry Technical Specification (TS) 6.4.A.7 was identified because 2-RC-PCV-2455A, the Unit 2 A pressurizer (PZR) spray valve, developed a body to bonnet mechanical joint leak as a result of the failure of the joint upper gasket to adequately seal the joint. The gasket inadequately sealed the body to bonnet joint due to a misalignment of the cage and the cage spacer assembly with the valve body. This misalignment caused the reactor coolant system (RCS) allowable unidentified leak rate to approach the TS limit on July 13, 2015, and subsequently required an unplanned Unit 2 shutdown. This issue was documented in the licensees corrective action program (CAP) as condition report (CR) 1002302. The inspectors concluded that the failure of the licensee to have the instructions necessary to successfully accomplish the purpose of 0-MCM-0414-13, Copes-Vulcan 4 inch, 1500 pound Control Valve, Model D-1000 with Bellows Overhaul, Revision 3, as required by Dominion procedure SPAP-0504, Technical Procedure Writers Guide, Revision 9, and to correctly measure and resolve the upper gasket crush on A PZR spray valve, was a performance deficiency (PD). Using IMC 0612, Appendix B, Issue Screening, dated September 7, 2012, the inspectors determined that the PD was more than minor because it was associated with the procedural quality attribute of the Initiating Events Cornerstone and adversely affected the cornerstone objective to limit the likelihood of events that upset stability and challenge critical safety functions during shutdown as well as power operations. Using IMC 0609.04, Initial Characterization of Findings, Table 2, dated June 19, 2012; the finding was determined to affect the Initiating Events Cornerstone. The inspectors screened the finding using Manual Chapter 0609, Appendix A, SDP for Findings at-Power, dated June 19, 2012, and determined that it screened as Green because the deficiency did not cause a loss of mitigation equipment relied upon to transition the plant to a stable shutdown condition. This finding has a cross-cutting aspect in the consistent process aspect of the human performance area, H.13, because the licensee did not use a systematic approach to evaluate all available data in deciding to return the A PZR spray valve to service during the spring 2014 refueling outage (RFO).
05000281/FIN-2015004-022015Q4SurryInadequate Testing Procedure Causes an Emergency Bus to DeenergizeA self-revealing, Green NCV of Surry TS 6.4.A.7 was identified because the Unit 2 H emergency bus was lost during performance of 2-PT-2.33A, Emergency Bus Undervoltage and Degraded Protection Test H Train, on September 16, 2015. An inadequate procedure allowed steps in the procedure to continue without verification that a tripped relay had not reset. Specifically, 2-PT-2.33A did not have instructions necessary to validate the state of the normally energized undervoltage (UV) relays once power was restored to the relay. This allowed an UV relay to remain in a deenergized state when the next relay was tested. As a consequence, the two of three coincidence was met for the Unit 2 H emergency bus to deenergize and automatically start and load the #2 emergency diesel generator (EDG) onto the Unit 2 H bus. This issue was documented in the licensees CAP as CR 1009999. The inspectors concluded that the failure of the licensee to have the instructions necessary to successfully accomplish the purpose of 2-PT-2.33A, as required by Dominion procedure SPAP-0504, was a PD. Using IMC 0612, Appendix B, Issue Screening, dated September 7, 2012, the inspectors determined that the performance deficiency was more than minor because it was associated with the procedural quality attribute of the Initiating Events Cornerstone and adversely affected the cornerstone objective to limit the likelihood of events that upset stability and challenge critical safety functions during shutdown as well as power operations. Using IMC 0609.04, Initial Characterization of Findings, Table 2, dated June 19, 2012; the finding was determined to affect the Initiating Events Cornerstone. The inspectors screened the finding using IMC 0609, Appendix A, SDP for Findings at-Power, dated June 19, 2012, and determined that it screened as Green because the deficiency did not involve the complete or partial loss of a support system that contributes to the likelihood, or cause, an initiating event and affected mitigation equipment. This finding has a cross-cutting aspect in the documentation aspect of the human performance area, H.7, because the licensee did not create and maintain complete and accurate documentation to validate that an emergency bus UV relay had been restored to its normal energized state during testing.
05000280/FIN-2015004-032015Q4SurryCharging Pump Service Water Pump Failure due to Inadequate Preventative MaintenanceA self-revealing Green NCV of Surry TS 6.4.D was identified because the preventative maintenance cleaning of the six inch service water (SW) piping upstream of the SW rotating strainers was deferred with insufficient technical justification. Specifically, the licensee did not follow procedure ER-AA-PRS-1010, Preventative Maintenance Task Basis & Maintenance Strategy, and provide justification for a differing disposition when they deferred the cleaning of the six inch SW header three times. A lack of maintenance on this piping allowed excessive biofouling and subsequent blockage of the SW rotating strainer to occur. This was discovered when the Unit 1 and 2 A charging service water (CHSW) pumps experienced a zero flow rate during performance of 0-OPT-VS-001, Control Room Air Conditioning System Pump and Valve Inservice Testing, Revision 43, on July 24, 2015. This issue was documented in the licensees CAP as CR 1003878. The inspectors concluded that the failure of the licensee to provide technical justification to defer the preventative maintenance of the six inch SW header was a PD. Using IMC 0612, Appendix B, Issue Screening, dated September 7, 2012, the inspectors determined that the PD was more than minor because it was associated with the equipment performance attribute of the Mitigating Systems Cornerstone, and it adversely affected the cornerstone objective to ensure the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences. Using IMC 0609.04, Initial Characterization of Findings, Table 2, dated June 19, 2012, the finding was determined to affect the Mitigating Systems Cornerstone. The inspectors screened the finding using IMC 0609, Appendix A, SDP for Findings at-Power, dated June 19, 2012, and determined that it screened as Green because the deficiency did not affect the design or qualification of the charging pump service water pump system and it did not represent a loss of system safety function. This finding has a cross-cutting aspect in work management aspect of the human performance area, H.5, because the licensee did not implement a process of planning, controlling, and executing work activities such that nuclear safety is the overriding priority. Specifically, ER-AA-102, Operability Determination, Revision 15 was not followed to ensure the management of risk commensurate to the work and the need for coordination with different groups was obtained.
05000281/FIN-2015004-042015Q4SurryInadequate Procedure Causes Main Turbine and Reactor TripA self-revealing Green NCV of Surry TS 6.4.A.7 was identified because Unit 2 tripped during performance of 2-OP-TM-001, Turbine Generator Startup to 20% - 25% Turbine Power, on July 21, 2015. An inadequate procedure allowed the main turbine (MT) governor valves to open rapidly during MT overspeed protection controller (OPC) testing, increasing MT first stage pressure above the P-2 and P-7 reactor protection system (RPS) permissive step points, and subsequently causing a reactor trip. Specifically, 2-OP-TM-001 did not have the minimum level of information needed to ensure that there was no speed error between MT speed and the setter position before initiating the OPC test. This allowed the test to be conducted with a speed error that caused the governor valves to open rapidly at the end of the test and subsequently cause a reactor trip. This issue was documented in the licensees CAP as CR 1003328. The inspectors concluded that the failure of the licensee to have the minimum level of information needed to ensure task critical actions in 2-OP-TM-001 and for operators to avoid error traps in conducting the MT OPC test, as required by Dominion procedure SPAP-0504, was a PD. Using IMC 0612, Appendix B, Issue Screening, dated September 7, 2012, the inspectors determined that the performance deficiency was more than minor because it was associated with the procedural quality attribute of the Initiating Events Cornerstone and adversely affected the cornerstone objective to limit the likelihood of events that upset stability and challenge critical safety functions during shutdown as well as power operations. Using IMC 0609.04, Initial Characterization of Findings, Table 2, dated June 19, 2012; the finding was determined to affect the Initiating Events Cornerstone. The inspectors screened the finding using IMC 0609, Appendix A, SDP for Findings at-Power, dated June 19, 2012, and determined that it screened as Green because the deficiency did not involve the complete or partial loss of a support system that contributes to the likelihood, or cause, an initiating event and affected mitigation equipment. This finding has a cross-cutting aspect in the documentation aspect of the human performance area, H.7, because the licensee did not create a complete procedure for testing the MT overspeed protection.
05000280/FIN-2015003-042015Q3SurryLicensee-Identified Violation10 CFR 50, Appendix B, Criterion III requires, in part, that measures shall be established to assure that applicable regulatory requirements and the design basis for those SSCs are correctly translated into specifications, drawings, procedures, and instructions. Contrary to the above, on January 27, 2015, the licensee discovered that abnormal procedure, 0-AP-37.01, Abnormal Environmental Conditions, used when there is a tornado watch or warning declared for Surry County or when hurricane force winds are expected in Surry County within 36 hours, did not have specific steps to shut the four total sliding missile shield doors on the Unit 1 and Unit 2 MSVHs. The shields are necessary to meet the design function of the MSVH for protection of the equipment inside the MSVH which includes the AFW pumps and other safety-related components in the main steam and AFW systems. This issue was discovered during a procedure revision walk-through. Using IMC 0609.04, Initial Characterization of Findings, Table 2, dated June 19, 2012, and IMC 0609 Appendix A, Significance Determination Process for Findings at-Power, dated June 19, 2012, the inspectors determined that a detailed risk evaluation was required because the finding could involve the total loss of any safety function, identified by the licensee through probability risk analysis (PRA) that contributes to external event initiated core damage accident sequences (i.e., severe weather event). A detailed risk assessment was performed by a regional SRA in accordance with NRC IMC 0609 Appendix A using the NRC Surry SPAR model. The major analysis assumptions included: a one year exposure period, the performance deficiency was modelled as a non-recoverable weather-related loss of offsite power (LOOP) with the Station Blackout DG and all AFW pumps on one unit failed, damage assumed if F2-F5 tornado winds occurred within the 100 square mile radius including the site, and no recovery credit for AFW or for closing the missile shield doors prior to damage. The dominant sequence was a success of the reactor protection system and the electric power system, late failure of AFW and failure of feed and bleed. The risk was mitigated by the low frequency of events requiring use of the sliding missile shields and the remaining mitigation equipment including the AFW unit cross-tie. The result of the risk evaluation was an increase in core damage frequency of <1.0E-6/year, a GREEN finding of very low safety significance. This issue was entered into the licensees CAP as CR 570365 and the abnormal procedure 0-AP-37.01 was revised with the correct operator actions.
05000280/FIN-2015003-012015Q3SurryCharging Pump Cubicle Floor Drain Backflow Preventer Failures during Unit 1 Safeguards Building FloodingA self-revealing, Green finding was identified because the instructions section of the procedure used to test floor drain back flow preventers (BFPs) did not include the instructions necessary to successfully fulfill the purpose of the procedure. A lack of testing methodology instructions allowed BFPs to be installed in the Unit 1 and Unit 2 charging (CH) pump cubicle floor drains that would not prevent backflow into the cubicles during low flow conditions. This was discovered when the Unit 1 and 2 CH pump cubicles filled with approximately two inches of water during the Unit 1 Safeguards building basement flooding event on May 20, 2015. This issue was documented in the licensees corrective action program (CAP) as condition reports (CRs) 580231 through 242. The inspectors concluded that the failure of the licensee to have the instructions necessary to successfully fulfill the purpose of 0-MPM-1900-02, Flood Protection Floor Drain Back Water Stop Valve Replacement as required by Dominion procedure SPAP-0504, Technical Procedure Writers Guide, and to correctly test the CH pump cubicle floor drain BFPs to prove functionality, was a performance deficiency (PD). Specifically, 0-MPM-1900-2 did not have instructions on the flow rate to fill the test stand and to observe that the BFP seats at a specified flow rate. Using IMC 0612, Appendix B, Issue Screening, dated September 7, 2012, the inspectors determined that the performance deficiency was more than minor because it was associated with the procedural quality attribute of the Mitigating Systems Cornerstone, and it adversely affected the cornerstone objective to ensure the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences. Specifically, the lack of complete testing instructions for BFPs allowed BFPs to be installed in the CH pump cubicle floor drains that would not seal during all flooding scenarios; and once cocked to the side during low flow, then had the potential to pass much higher flow rates into the CH pump cubicles. Using IMC 0609.04, Initial Characterization of Findings, Table 2, dated June 19, 2012, the finding was determined to affect the Mitigating Systems Cornerstone. The inspectors screened the finding using Manual Chapter 0609, Appendix A, Significance Determination Process (SDP) for Findings at-Power, dated June 19, 2012, and determined that it screened as Green because the deficiency involved the degradation of equipment specifically designed to mitigate a flooding initiating event, but did not involve the total loss of any safety function. This finding has a cross-cutting aspect in the documentation aspect of the human performance area, H.7, because the licensee did not have an adequate test procedure to ensure that the floor drain BFPs would seal during low flow backflow conditions.
05000280/FIN-2015003-022015Q3SurryFailure to Follow Procedure during Maintenance Results in Service Water Header InoperabilityA self-revealing, Green NCV of Technical Specifications (TS) 6.4.D was identified for failure to follow procedure WM-AA-101, Work Order Planning, Revision 1. Specifically, the licensee inappropriately revised a work order which resulted in the actuator and hand wheel assembly on 1-SW-495, the 1D Service Water (SW) header inlet isolation valve, being rotated incorrectly. The incorrect rotation resulted in the 1D SW header being inoperable from November 19, 2013, the time the 1D SW header was placed in service following 1-SW-495 replacement, until the issue was corrected on April 11, 2014. This issue was documented in the licensees CAP as CR 544361 The inspectors determined that the failure to follow procedure WM-AA-101, Work Order Planning, Revision 1, was a performance deficiency that was within the licensees ability to foresee and correct and should have been prevented. The inspectors determined that the finding 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. Specifically, the rotation of the actuator and hand wheel assembly of 1-SW-495 resulted in the inoperability of the 1D SW header from November 19, 2013 until April 11, 2014. Using IMC 0609.04, Initial Characterization of Findings, Table 2, dated June 19, 2012, and IMC 0609 Appendix A, SDP for Findings at-Power, dated June 19, 2012, the inspectors determined that a detailed risk evaluation was required because the finding represented an actual loss of system function for greater than the TS allowed outage time for both the main control room (MCR) air conditioning system and the charging SW system during the two periods where only one SW header was operable. The finding had a cross-cutting aspect in human performance, work management, H.5, because the organization did not appropriately control or implement the maintenance activity associated with 1-SW-495 and also did not identify the need for coordination with other groups when the scope of the planned work was changed.
05000280/FIN-2015003-032015Q3SurryFailure to Verify Adequacy of Class 1E 125VDC Branch Circuit Breaker DesignThe team identified a Green non-cited violation of 10 CFR Part 50, Appendix B, Criterion III, Design Control, for the licensees failure to verify or check the adequacy of design of the Class 1E 125 volt direct current (VDC) molded case circuit breakers (MCCBs). The licensee entered the issue into their CAP as CRs 559872 and 59875 and performed an immediate determination of operability, which determined the Class 1E 125VDC switchgear to be operable. The licensees failure to assure the quality levels of MCCBs through the specification of requirements known to promote high quality, such as requirements for design, for the de-rating of components, for manufacturing, quality control, inspection, calibration, and test, as specified by IEEE 279, Section 4.3, was a performance deficiency. The performance deficiency was determined to be more than minor because it was associated with the design control attribute of the Mitigating Systems 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 adequately assess the electrical rating of electrical components could prevent the Class 1E 125VDC circuits from performing their safety function. The team determined the finding to be of very low safety significance (Green) because the finding was a deficiency affecting the design or qualification of a mitigating structure, system, or component, which maintained its operability or functionality. The team determined that no cross-cutting aspect was applicable because the finding was not indicative of current licensee performance.
05000280/FIN-2015002-012015Q2SurryFailure to conduct a detailed visual examination of the concrete-liner interface for the Unit 1 containmentAn NRC-identified NCV of 10 CFR 50.55a, Codes and Standards, was identified for the licensees failure to conduct a detailed visual examination of the concrete-liner interface for the Unit 1 containment, per the American Society of Mechanical Engineers (ASME) Boiler and Pressure Vessel Code (BPVC) Section XI, Subsection IWE 1241, Table IWE-2500-1, Category E-C, Item E 4.11. This issue was documented in the licensees CAP as CR 578448. The licensees failure to conduct a detailed visual examination of the concrete-liner interface of the Units 1 and 2 containment in accordance with the ASME BPVC Section XI, Subsection IWE 1241, Table IWE-2500-1, Category E-C, Item E 4.11, was a PD that was within the licensees ability to foresee and correct. Using Manual Chapter 0612, Appendix B, Issue Screening, dated September 7, 2012, the inspectors determined that the PD was more than minor because, if left uncorrected, it had the potential to lead to a more significant safety concern. Specifically, detailed visual inspections of the containment metallic liner provides assurance that the liner remains capable of performing its intended safety function, and in the absence of such inspections, corrosive conditions could progress to challenge that capability. Using Manual Chapter 0609.04, Initial Characterization of Findings, dated June 19, 2012, the finding was determined to affect the Barrier Integrity Cornerstone. The inspectors screened the finding using IMC 0609, Appendix A, Significance Determination Process (SDP) for Findings at-Power, dated June 19, 2012, and determined that the finding was of very low safety-significance (Green) because the finding did not represent an actual open pathway in the physical integrity of the reactor containment. The team determined that no cross cutting aspect was applicable to this performance deficiency because this finding was not indicative of current licensee performance.
05000280/FIN-2015002-022015Q2SurryA MDAFW Pump Motor Outboard Bearing DamagedA self-revealing NCV of Surry Technical Specification (TS) 6.4.D was identified because the Unit 1 A motor driven auxiliary feedwater (MDAFW) pump motor outboard bearing thermocouple was improperly installed while installing a new motor on the MDAFW pump in November, 2013. The improper thermocouple installation in the bearing caused the bearing to fail while the pump was running on January 5, 2015. This issue was documented in the licensees corrective action program (CAP) as condition report (CR) 568663. The inspectors concluded that the failure of the licensee to use a procedure to remove and reinstall the A MDAFW pump motor thermocouples was a performance deficiency (PD). Using Manual Chapter 0612, Appendix B, Issue Screening, dated September 7, 2012, the inspectors determined that the PD was more than minor because it was associated with the human performance attribute of the Mitigating Systems Cornerstone, and it adversely affected the cornerstone objective to ensure the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences. Specifically, the incorrect installation of the motor outboard bearing thermocouple eventually damaged the bearing and caused the A MDAFW pump to become inoperable. Using Manual Chapter 0609.04, Initial Characterization of Findings, dated June 19, 2012, the finding was determined to affect the Mitigating Systems Cornerstone. The inspectors screened the finding using IMC 0609, Appendix A, Significance Determination Process (SDP) for Findings at-Power, dated June 19, 2012, and determined that it screened as Green because the deficiency did not affect the design or qualification of the AFW system and it did not represent a loss of system safety function. This finding has a cross-cutting aspect in the Challenge the Unknown aspect of the human performance area, H.11, because the individuals involved in removing and installing the thermocouples did not stop when faced with a work order that did not have the appropriate procedure reference for the action they were taking.
05000281/FIN-2015001-012015Q1SurryFailure to Identify Charging Service Water Pipe LeakAn NRC-identified, non-cited violation (NCV) of 10 CFR 50, Appendix B, Criterion XVI, Corrective Action, was identified because the licensee failed to promptly identify a condition adverse to quality associated with the material condition of the Unit 2 charging service water (CH/SW) piping. Specifically, the NRC resident inspectors identified a leak in the discharge piping of the Unit 2 A CH/SW pump on November 24, 2014. The licensee had previously identified a leak on the Unit 1 B CH/SW pump discharge piping on June 16, 2014. The issue was documented in the licensees corrective action program (CAP) as condition report (CR) 563166. The licensees failure to identify a condition adverse to quality associated with the material condition of the Unit 2 A CH/SW piping was a performance deficiency (PD). The inspectors determined that the PD was 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 availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences. Specifically, not having compensatory actions in place for CH/SW Green Thread piping that has been prone to through-wall leaks, left the licensee susceptible to undetected leaks from the CH/SW piping systems. Using Manual Chapter 0609.04, Initial Characterization of Findings, Table 2, dated June 19, 2012, the finding was determined to adversely affect the Mitigating Systems Cornerstone. The inspectors screened the finding using Manual Chapter 0609, Appendix A, Significance Determination Process (SDP) for Findings at- Power, dated June 19, 2012, and determined that it screened as Green because the PD did not affect the design or qualification of the CH/SW system and the leak rate did not represent an actual loss of system safety function. This finding has a cross-cutting aspect in the evaluation component of the problem identification and resolution, P.2, because the organization did not thoroughly evaluate issues to ensure that resolutions address causes and extent of conditions commensurate with their safety significance. Specifically, the license did not institute compensatory actions for a long-term corrective action on CH/SW piping that has had a recent history of developing through-wall leaks.
05000281/FIN-2014005-012014Q4SurryUnit 2 Trip Due to Loose RPS Wire ConnectionAn NRC-identified, non-cited violation (NCV) of Surry Technical Specification (TS) 6.4, Unit Operating Procedures and Programs, Section A.7 was identified because Surry procedure 0-ECM-1801-01, Westinghouse Type BF BFD or NBFD65NR Relay Replacement did not include a torque value for the reactor protection system (RPS) relay terminal screws to a field wiring connection. Subsequently, Unit 2 tripped on October 13, 2014, when a field wire connection became loose from the terminal end of a RPS trip relay and caused a reactor trip breaker to open. The issue was documented in Surrys corrective action program (CAP) as condition report (CR) 561820. The licensees failure to specify a torque value in procedure 0-ECM-1801-01 was a performance deficiency (PD) that was within the licensees ability to foresee and correct. Specifically, the licensee removed the correct torque value from the procedure based on a licensee procedure action request (PAR) that was incorrectly implemented. The inspectors determined that the PD was more than minor because it was associated with the procedural quality attribute of the Initiating Events Cornerstone and adversely affected the cornerstone objective to limit the likelihood of events that upset stability and challenge critical safety functions during shutdown as well as power operations. Specifically, the procedure that controlled the connection of electrical termination to RPS relays did not specify a torque value and therefore, left it up to the technician to determine the tightness of the connection. Using Manual Chapter 0609.04, Initial Characterization of Findings, Table 2, dated June 19, 2012, the finding was determined to affect the Initiating Events Cornerstone. The inspectors screened the finding using Manual Chapter 0609, Appendix A, Significance Determination Process (SDP) for Findings at-Power dated June 19, 2012, and determined that it screened as Green because the deficiency did not cause a loss of mitigation equipment relied upon to transition the plant to a stable shutdown condition. This finding has a cross-cutting aspect in the documentation component of the human performance area, H.7, because the organization failed to maintain complete, accurate and up-to-date documentation for the replacement of RPS relays.
05000280/FIN-2014005-022014Q4SurryLicensee-Identified ViolationSurry TS 6.4.A.3 requires, in part, that detailed written procedures with appropriate instructions shall be provided for conditions that include: action to be taken for specific and foreseen malfunctions of systems or components including alarms, primary system leaks and abnormal reactivity changes. Contrary to the above, on September 4, 2014, the licensee discovered that the annunciator response procedure, 0-VSP-M4, Flood Control Panel Trouble, used to mitigate ESGR flooding, did not have specific steps to direct an operator on how to isolate a leak. This was revealed when the licensee discovered that their current PRA model assumed an incorrect low flow rate for a break in SW piping in mechanical equipment room MER-3. Consequentially, the licensee had to take compensatory actions to isolate the SW flow path by shutting 1-SW-846, MER-3 chiller SW to Unit 1 discharge tunnel, until the PRA model was analyzed with the new flow rate and 0- VSP-M4 was changed. This finding is of very low safety significance (Green) because the completed PRA analysis did not affect the design or qualification of the SW system and it did not represent a loss of system or train safety function. This issue was entered into the licensees CAP as CR 557706 and the annunciator response procedure was revised with the correct operator actions.
05000280/FIN-2014005-032014Q4SurryLicensee-Identified ViolationSurry TS 6.4.D requires, in part, that procedures described in section 6.4.A shall be followed. Surry TS 6.4.A.1 requires, in part, that detailed written procedures with appropriate check-off lists and instructions shall be provided for conditions which include: normal startup, operation, and shutdown of a unit, and of all systems and components involving nuclear safety of the station. These requirements are implemented, in part, by Dominion procedure 1-OP-RS-001A, Outside Recirculation Spray System Alignment, Revision 9, and independently verified, in part, by using Dominion procedure PI-AA-500, Verification Practices, Revision 3. Contrary to the above, on November 13, 2013, Dominion personnel failed to independently verify, in accordance with PI-AA-500, 1-RS-92 and 1-RS-97, the Unit 1 A OSRS pump seal tank inlet and outlet isolation valves were tie-wrapped open when performing procedure 1-OP-RS-001A. Consequentially, on November 9, 2014, the licensee found both of these valves tie-wrapped shut while performing a check of all Unit 1 valve locking devices. The licensee declared the Unit 1 A OSRS pump inoperable until the valves were repositioned opened. This finding is of very low safety significance (Green) because it did not affect the design or qualification of the recirculation spray system and it did not represent a loss of system or train safety function. This issue was entered into the licensees CAP as CR 564824.
05000250/FIN-2014004-012014Q3Turkey PointFailure to Identify and Correct Unsealed Condulet to Prevent Water IntrusionA self-revealing, non-cited violation (NCV) of 10 CFR Part 50, Appendix B, Criterion XVI, Corrective Action, was identified for the licensees failure to implement corrective actions to prevent water intrusion into electrical conduits that affected safety related equipment. Specifically, the licensee failed to establish corrective actions to prevent water intrusion into the power supply for the Unit 3 B train (3B) pressurizer back-up heaters. After discovery of the condition, the licensee completed immediate corrective actions to apply waterproofing sealant to an unsealed condulet elbow that was the source of the pressurizer back-up heater water intrusion. The licensee entered this issue into their corrective action program as ARs 1985831 and 1986395. This finding was more than minor because it was associated with the equipment performance attribute of the mitigating systems cornerstone and adversely affected its objective to ensure the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences. Specifically, the licensee failed to implement corrective actions to prevent water intrusion events which resulted in the inoperability of 3B pressurizer back-up heaters. The inspectors evaluated the significance of the finding under the mitigating systems cornerstone using Table 2 of Attachment 4 (dated June 19, 2012) and Exhibits 2 and 4 of Appendix A (dated June 19, 2012) to Inspection Manual Chapter 0609, Significance Determination Process, (dated June 2, 2011). The inspectors determined the finding was of very low safety significance (i.e., Green) because the exhibit criteria did not screen to a detailed risk assessment. A cross-cutting aspect was not identified because this performance deficiency occurred in 2007 and there have been no recent opportunities for the licensee to apply current processes and procedures for this issue. Therefore, the inspectors concluded that the performance deficiency was not indicative of current licensee performance.
05000250/FIN-2014004-032014Q3Turkey PointLicensee-Identified ViolationTurkey Point Nuclear Generating Unit 3 and Unit 4 Technical Specification (TS) 3.3.1 required, in part, that the reactor trip system instrumentation channels and interlocks of Table 3.3-1 shall be operable. Contrary to the above, for approximately 50 days from April 2013 until June 2013, the steam versus feed water flow mismatch reactor trip functions associated with Unit 4 feed water flow instruments F-4-487, F-4-496, and F-4-497 were inoperable because they exceeded their TS allowed actuation set points specified by TS Table 2.2-1, and the affected channels were not placed in trip within six hours or the unit placed in cold shutdown as required by TS. Additionally, for approximately 162 days from August 2012 until February 2013, the steam-feed water flow mismatch reactor trip function associated with Unit 3 feed water flow instrument F-3-476 was inoperable because it exceeded its TS allowed actuation set point and the affected channel was not placed in trip within six hours and the unit placed in cold shutdown as required by TS. The inspectors assessed the significance of the violation using Inspection Manual Chapter 0609 Attachment 4, Appendix A and Exhibit 2 (June 19, 2012). The inspectors noted that the diverse low-low steam generator level reactor trip safety function was not affected by the inoperable feed water flow instruments and the violation did not represent a complete loss of the anticipatory steam versus feed water flow mismatch reactor trip function. Therefore, the inspectors concluded that violation was of very low safety significance (i.e., Green) because the violation was not associated with a significant functional degradation of the reactor protection system. The licensee completed immediate corrective actions following discovery of the condition to adjust the affected instruments to within TS allowed values and entered the issue into the corrective action program as action request (AR) 1961512.
05000281/FIN-2014003-012014Q2SurryInadequate Amount of Packing in Pressurizer Spray ValveA self-revealing NCV of Surry Technical Specification (TS) 6.4.A.7 was identified because 2-RC-PCV-2455A, the Unit 2 A pressurizer (PZR) spray valves packing gland was repacked with the incorrect number of packing rings in May, 2008. When the Unit 2 A PZR spray valve bellows failed in March 2014, the amount of packing in the valve was insufficient to prevent packing leakage. This leakage approached the technical specification (TS) allowable unidentified reactor coolant system (RCS) leak rate on March 19, 2014, and subsequently required an unplanned unit shutdown. The issue was documented in Surrys corrective action program (CAP) as CR 542547. The failure of the licensees packing control program to list the correct number of packing rings in the packing control form for the repack of 2-RC-PCV-2455A, the Unit 2 A PZR spray valve, was a performance deficiency that was within the licensees ability to foresee and correct. Specifically, the licensee did not thoroughly evaluate decreasing the number of packing rings from five to four when packing control was shifted from the PZR safety valve overhaul procedure to the licensees Packing Control Program. As a consequence of the inadequate number of packing rings, the Unit 2 A PZR spray valve experienced a packing leak that approached the TS allowable unidentified RCS leak rate on March 19, 2014, which subsequently required an unplanned shutdown of Unit 2. The inspectors determined that the performance deficiency was more than minor because it was associated with the procedural quality attribute of the Initiating Events Cornerstone and adversely affected the cornerstone objective to limit the likelihood of events that upset stability and challenge critical safety functions during shutdown as well as power operations. Specifically, an incorrect number of packing rings listed on the packing control form eventually allowed packing leakage to approach the TS limit. Using Manual Chapter 0609.04, Initial Characterization of Findings, Table 2, dated June 19, 2012; the finding was determined to affect the Initiating Events Cornerstone. The inspectors screened the finding using Manual Chapter 0609, Appendix A, Significance Determination Process (SDP) for Findings at- Power dated June 19, 2012, and determined that it screened as Green because the deficiency did not cause a loss of mitigation equipment relied upon to transition the plant to a stable shutdown condition. Because the PD occurred outside of the nominal three-year period for present performance, no cross-cutting aspect has been assigned.
05000280/FIN-2013005-012013Q4SurryApplication of ASME Section XI, Table IWB 2500-1, Item B10.10, Inspection Requirements and Note 1 ExemptionsThe inspectors identified an unresolved item related to the inspection of the reactor pressure vessel (RPV) component supports as required by ASME BPVC Section XI, for which additional information is needed to determine if the issue of concern represents a performance deficiency or a violation of the regulatory requirements. The code of record for the current ISI program at Surry Power Station Unit 1 is the 1998 Edition of the ASME BPVC Section XI with the 2000 addenda. This Code edition includes inspection requirements for both nuclear class 1 piping and vessel supports (Subsection IWF) and their attachment welds (Subsection IWB). Subsection IWB, Table IWB-2500-1, item number B10.10, describes the examination requirements for welded attachments for vessels, piping, pumps, and valves. Note 1 of Table IWB- 2500-1 states that attachment welds (weld buildup) on nozzles that are in compression under normal load conditions and provide only component support are excluded from the surface examination requirements. The note also provides additional conditions to identify what type welded attachment configurations require inspection. Table IWB- 2500-1 also references Figures IWB-2500-13, -14 and -15 to further describe the examination requirements. The inspectors noted that the scope of the Surry Unit 1 ISI program for the inspection of the nuclear class 1 RPV supports did include the requirements for the IWF portion of the ASME Section XI code required inspections. However, the inspectors identified that the licensee excluded the surface examination requirements for the RPV support attachment welds required by Table IWB-2500-1, item number B10.10 based on the exemptions provided by Note 1 of the table. The licensees position was that the surface examinations are not required based on the exclusion criteria provided in Note 1 for attachment welds under compressive loads during normal conditions and the configurations described in Figures IWB-2500-13, -14 and -15. The inspectors reviewed design basis documents for the Unit 1 RPV supports and identified that the normal loading conditions of the supports included both compressive and shear loads. The inspectors determined that additional information and discussion with the NRC Office of Nuclear Reactor Regulation (NRR) staff was required, in order to determine if the licensees interpretation and implementation of the exemptions in Table IWB-2500-1 were in compliance with the ASME BPVC Section XI. Therefore, the NRR and Region II staff agreed to submit a Task Interface Agreement (TIA), which could involve the submittal of a formal inquiry to the applicable ASME BPVC committee to request an interpretation of the examination requirements and exemptions in Table IWB- 2500-1 for welded attachments for vessels and piping. The NRC initiated TIA-2014-02 to determine the staffs position on whether the configuration of the RPV supports at Surry meets the exclusion criteria in ASME BPVC Section XI. This issue remains unresolved until the resolution of TIA-2014-02 to determine if the issue of concern represents a performance deficiency or a violation of regulatory requirements. This issue is identified as URI 05000280/2013005-01, Application of ASME Section XI, Table IWB 2500-1, Item B10.10, Inspection Requirements and Note 1 Exemptions.
05000269/FIN-2013002-022013Q1OconeeLicensee-Identified Violation10 CFR 50.65 (a)(4) stated in part that the licensee shall assess and manage the increase in risk that may result from the proposed maintenance activities. Contrary to the above, on February 17, 2013, the licensee failed to assess and manage the risk when placing the 1A reactor building spray train in service for borated water storage tank recirculation for sampling. This condition made train A reactor building spray inoperable. This combined with train A high pressure injection being inoperable due to 1HP-24 (high pressure injection borated water storage tank suction isolation valve) the plant was in an orange risk condition. The licensee previously evaluated risk for an emergent condition associated with 1HP-24 and determined 1HP-24 was available and that the unit was in a yellow risk condition. The licensee recognized this omission later that day and entered the condition into their corrective action program as PIP-O-13-01822. The licensee also restored the reactor building spray train to its normal standby lineup. This finding was assessed using IMC 0609, Phase 1 screening worksheet of Attachment 4 and Appendix K was determined to be of very low safety significance (Green), because the incremental core damage probability is less than 1E-6.
05000269/FIN-2013002-012013Q1OconeeFailure to Maintain Pressure Boundary in Unit 3 Control Battery RoomAn NRC-identified non-cited violation of 10 CFR 50, Appendix B, Criterion XVI, Corrective Action, was identified for the licensees failure to take timely corrective actions for a condition adverse to quality. The licensee failed to take timely actions to correct the degraded, nonconforming condition resulting from a sheet metal plate over a penetration in the Unit 3 control battery room pressure boundary wall. The licensee entered this issue into their corrective action program (CAP), performed an operability evaluation, and declared the wall operable but degraded/non-conforming (OBDN). The performance deficiency (PD) was more than minor because it was associated with the Mitigating Systems Cornerstone attribute of Design Control and adversely impacted the cornerstone objective in that functionality of the pressure boundary was not maintained. The finding was of very low safety significance (Green) because it did not actually result in a safety related system being inoperable. The cause of the finding was directly related to thoroughly evaluate problems in the Corrective Action Program component of the Problem Identification and Resolution area because the licensee failed to evaluate the sheet metal plate to maintain the safety-related pressure boundary function of the battery room wall.
05000280/FIN-2011003-082011Q2SurryLicensee-Identified ViolationNUHOMS Certificate of Compliance 1030, Amendment 0, Technical Specifications 2.1.c, Functional and Operating Limits, requires, in part, that the spent nuclear fuel stored in each 32PTH DSC/HSM-H at the Independent Spent Fuel Storage Installation (ISFSI) is to be qualified for four (4) heat load zones designated as Zones 1a, 1b, 2 and 3. Contrary to this requirement, the licensee identified that it failed to properly load fuel assemblies into four NUHOMS Dry Shielded Canisters (DSCs) resulting in the fuel assemblies exceeding the decay heat limit for the loading zones in two of the four center zones. Specifically, the Zone 1a and Zone 1b locations were reversed, resulting in the DSC Zone 1b heat load limits being slightly exceeded (less than one per cent in the worst case) at the time of loading. An evaluation performed by the licensee showed that all of the affected DSCs are currently in a safe condition as loaded in the HSMs. This issue is in the licensees CAP as CR419237, NUHOMS DSCs Loaded to Incorrect Heat Load Limits for Specific Orientation. This Severity Level IV violation is being treated as a non-cited violation (NCV), consistent with Section 2.3.2.b of the NRC Enforcement Policy; specifically, the violation was identified by the licensee, the issue was placed into the licensees CAP, the violation was not repetitive as a result of inadequate corrective action, and the violation was not willful.
05000280/FIN-2011003-072011Q2SurryLicensee-Identified ViolationLicensee Technical Specification, 3.1.B.3, requires, in part, that the pressurizer heatup rate shall not exceed 100 degF per hour. Contrary to this, the licensee identified that this specification was exceeded on Unit 2 on May 26, 2011. The licensee created Engineering Technical Evaluation ETE-SU-2011-0073 to evaluate the acceptability of the Pressurizer for continued operation. The evaluation concluded that the structural integrity impact of the transient was within design fatigue analysis margin and therefore did not affect Pressurizer operability. The inspectors determined the finding was more than minor because it adversely impacted the Barrier Integrity cornerstone objective to provide reasonable assurance that physical design barriers (reactor coolant system) protect the public from radionuclide releases caused by accidents or events. The inspectors determined that this finding was a low safety of significance (Green) because there was no actual degradation of the barrier function of the control room against radiological hazards, smoke, or toxic atmosphere. The inspectors determined that licensee correctly evaluated the finding and developed appropriate corrective action as documented in the licensees CAP as CR428788.
05000280/FIN-2011003-062011Q2SurryLicensee-Identified ViolationLicensee Technical Specification, 3.1.B.3, requires, in part, that the pressurizer heatup rate shall not exceed 100 degF per hour. Contrary to this, the licensee identified that this specification was exceeded on Unit 1 on April 20, 2011. The licensee created Engineering Technical Evaluation ETE-CEM-2011-0005 to evaluate the acceptability of the Pressurizer for continued operation. The evaluation concluded that the structural integrity impact of the transient was within design fatigue analysis margin and therefore did not affect Pressurizer operability. The inspectors determined the finding was more than minor because it adversely impacted the Barrier Integrity cornerstone objective to provide reasonable assurance that physical design barriers (reactor coolant system) protect the public from radionuclide releases caused by accidents or events. The inspectors determined that this finding was a low safety of significance (Green) because there was no actual degradation of the barrier function of the control room against radiological hazards, smoke, or toxic atmosphere. The inspectors determined that licensee correctly evaluated the finding and developed appropriate corrective action as documented in the licensees CAP as CR423197.
05000280/FIN-2011003-052011Q2SurryLicensee-Identified ViolationLicensee Technical Specification, 3.1.B.3, requires, in part, that the spray shall not be used if the temperature difference between the pressurizer and the spray fluid is greater than 320 deg F. Contrary to this, the licensee identified that this specification was exceeded on Unit 2 on April 17, 2011. The licensee created Engineering Technical Evaluation ETE-SU-2011-0058 to evaluate the acceptability of the Pressurizer for continued operation. The evaluation concluded that the structural integrity impact of the transient was within design fatigue analysis margin and therefore did not affect Pressurizer operability. The inspectors determined the finding was more than minor because it adversely impacted the Barrier Integrity cornerstone objective to provide reasonable assurance that physical design barriers (reactor coolant system) protect the public from radionuclide releases caused by accidents or events. The inspectors determined that this finding was a low safety of significance (Green) because there was no actual degradation of the barrier function of the control room against radiological hazards, smoke, or toxic atmosphere. The inspectors determined that licensee correctly evaluated the finding and developed appropriate corrective action as documented in the licensees CAP as CR422778.
05000280/FIN-2011003-042011Q2SurryLicensee-Identified ViolationLicensee Technical Specification, 3.1.B.3, requires, in part, that the spray shall not be used if the temperature difference between the pressurizer and the spray fluid is greater than 320 deg F. Contrary to this, the licensee identified that this specification was exceeded on Unit 1 on April 17, 2011. The licensee created Engineering Technical Evaluation ETE-SU-2011-0042 to evaluate the acceptability of the Pressurizer for continued operation. The evaluation concluded that the structural integrity impact of the transient was within design fatigue analysis margin and therefore did not affect Pressurizer operability. The inspectors determined the finding was more than minor because it adversely impacted the Barrier Integrity cornerstone objective to provide reasonable assurance that physical design barriers (reactor coolant system) protect the public from radionuclide releases caused by accidents or events. The inspectors determined that this finding was a low safety of significance (Green) because there was no actual degradation of the barrier function of the control room against radiological hazards, smoke, or toxic atmosphere. The inspectors determined that licensee correctly evaluated the finding and developed appropriate corrective action as documented in the licensees CAP as CR422769.
05000280/FIN-2011003-032011Q2SurryInadequate Qualification Testing of Fire Barrier Penetration SealsA Green non-cited violation of Surry Units 1 and 2 Operating License Condition 3.I, Fire Protection, was identified by the inspectors for failure to have adequate qualification testing results, as directed by Appendix A to Branch Technical Position APCSB 9.5-1. Specifically, the licensee did not have sufficient testing results to qualify certain aluminum conduit configurations that penetrate 3-hour fire rated barriers separating fire areas containing redundant equipment required for safe shutdown. As part of the corrective actions, the licensee performed testing to determine the qualification of aluminum conduit penetrations, and performed modifications, as appropriate, to restore compliance. The finding is more than minor because it is associated with the reactor safety Mitigating Systems cornerstone attribute of protection against external factors (i.e., fire) and it affects the cornerstone objective of ensuring the reliability and capability of systems that respond to initiating events. Specifically, not having qualification testing results for aluminum conduits that penetrate fire rated barriers adversely affected the fire confinement capability defense-in-depth element because subsequent testing revealed some conduit configurations that did not meet the penetration seal criteria established in Branch Technical Position APCSB 9.5-1. The inspectors used the guidance of NRC Inspection Manual Chapter 0609, Appendix F, Fire Protection Significance Determination Process, and determined that the performance deficiency represented a finding of very low safety significance (Green). Specifically, the fire areas in question either contained a non degraded automatic gaseous or water-based fire suppression system, or the exposed fire areas did not contain potential damage targets that are unique from those in the exposing fire areas. Inspectors determined that no cross cutting aspect was applicable to this performance deficiency because this finding was not indicative of current licensee performance.
05000280/FIN-2011003-022011Q2SurryFailure to Classify and Declare a Notification of Unusual EventA Green non-cited violation was identified by the inspectors for the licensees failure to classify and declare a Notification of Unusual Event when conditions warranted as required by 10 CFR 50.54(q) and 10 CFR 50.47(b)(4). The inspectors reviewed IMC0612, Appendix B, and determined that the finding was more than minor because it adversely affected the Emergency Response Organization performance attribute of the Emergency Preparedness 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. Since the finding involved a failure to comply with regulatory requirements during an actual event, the inspectors reviewed IMC0609, Appendix B, Sheet 2, and determined that this was a finding of very low safety significance (Green) because it involved the failure to declare a Notification of Unusual Event. The cause of this finding involved the cross-cutting area of human performance, the component of decision making, and the aspect of conservative assumptions and safe actions, H.1(b), because the licensee failed to use conservative assumptions in the decision to not classify and declare the event as an Unusual Event.
05000280/FIN-2011003-012011Q2SurryUnplanned Dilution of Unit 2 RCSOn May 28, 2011, while Unit 2 was operating in Intermediate Shutdown (>200 F, 310 psi), a control room operator noticed a decreasing level trend in the primary grade water tank over the past 2.5 hours. Additionally, it was noted that volume control tank and pressurizer level trends were increasing and charging seal injection flow was 101 gpm with letdown flow of 85 gpm. The licensee entered their abnormal procedure for emergency boration and conducted two emergency borations of the RCS while sampling RCS boron concentration and monitoring shutdown margin. Subsequently, it was identified that the cation demineralizer primary grade header isolation valve, 2-CH-19, indicated closed but was allowing primary grade water to leak by. This caused reverse flow through the cation demineralizer and introduced primary grade water into the RCS via the VCT. The licensee estimated that up to 30,000 gallons of PG water could have entered the RCS. Just prior to this event maintenance was conducted on 2-CH-19 and the valve was returned to service in a condition that allowed the primary grade water leakage flow path described above. The licensee entered this issue into their CAP as CR428947, and initiated Root Cause Evaluation (RCE) 001054. The inspectors require additional information, including the licensees completed investigation in RCE001054, to determine if there is a performance deficiency which is more than minor. This issue is identified as URI 05000281/2011003-01, Unplanned Dilution of Unit 2 RCS.
05000281/FIN-2011002-012011Q1SurryReactor Coolant System Instrumentation Erratic Level IndicationOn February 2, 2011, while Unit 2 was operating at 100% power, the C loop RCS cold leg loop isolation valve, 2-RC-MOV-2595, experienced stem to disc separation resulting in a low RCS flow condition in the C RCS loop and subsequent automatic reactor trip. The licensee decided to repair the valve in Cold Shutdown by draining the RCS to mid-loop. The RCS standpipe is relied upon to provide both local and remote indication of RCS level during reduced inventory and mid-loop configurations. The licensee drained to reduced inventory and was forced to re-fill the RCS due to the unreliable level indication of 2-RC-LR-200A. Troubleshooting was performed on the 13 Enclosure electronics of the level recorder and associated circuitry and the instrument was tested before a second attempt at draining to mid-loop was commenced. During the second attempt 2-RC-LR-200A again became unreliable and operators were again forced to refill the RCS. The licensee then performed more in-depth troubleshooting of the instrumentation and performed a third drain down to mid-loop conditions once it had been returned to service. The third attempt was successful, although the instruments still experienced several instances of erratic indication. The licensee entered this issue into their CAP as CR413227, and initiated Apparent Cause Evaluation (ACE) 018543. The inspectors require additional information, including the licensees completed investigation in ACE018543 to determine if there is a performance deficiency which is more than minor. This issue is identified as URI 05000281/2011002-01, Reactor Coolant System Instrumentation Erratic Level Indication.
05000280/FIN-2009007-012009Q2SurryQualification of Fire Barrier Floor/Wall Penetration of Aluminum Conduit Through SleeveThe team identified an unresolved item (URI) involving the qualification documentation for wall and floor fire barrier penetration seals. While inspecting the wall and floor fire barrier penetration seals, the team requested the licensees documentation for the qualification of a particular penetration seal configuration. That configuration was for one aluminum schedule 40 conduit (of various sizes as applicable) penetrating a 6 in. diameter floor or wall sleeve where the floor or wall was of poured concrete construction and the sleeve void around the conduit was filled with foamed silicon to the thickness of the floor or wall. The documentation package requested should establish a 3-hour fire rating, since the rated fire barrier walls and floors were required to have a 3-hour rating. In response, the licensee presented Impell Corporation Calculation No. 1250-111-C01, Penetration Seal Configuration Documentation Package, 10 in. Dow Corning Q3-6548 Silicone RTV Sealing Foam/North Anna and Surry, Rev.1. The qualification package or calculation was based on a tested configuration similar to that described above, except that the conduit was 3 in. or 4 in. galvanized steel. The team informed the licensee that this calculation was not valid to qualify aluminum conduit due to the lower melting temperature and greater heat conductance of aluminum as compared to steel. The licensee later transmitted supplemental information which included a fire barrier penetration seal fire test report for large diameter aluminum conduits through a sleeve. This new information was not a formal calculation comparing it to any installed penetration seal configuration at Surry. Moreover, certain aspects of the test data such as the temperature rise on the unexposed surfaces may not meet the licensing basis. At the time of issuance of this report, the team did not have sufficient information to determine the design criteria of that penetration seal. The team was aware that the fire barrier penetration seal configurations in question could probably be qualified by existing nuclear industry penetration seal testing data; therefore, there was no immediate safety concern. The licensee Initiated CR 339567 with an action item to establish a valid qualification package for the penetration configuration described above. URI 05000280, 281/2009007-01, Qualification of Fire Barrier Floor/Wall Penetration of Aluminum Conduit Through Sleeve, was established to track this issue until the final qualification package is reviewed
Retrieved from "https://kanterella.com/Special:Ask/-5B-5BCategory:Finding-5D-5D-20-5B-5BInspector::Clint-20Jones-5D-5D/-3FQuarter/-3FSite/-3FTitle/-3FDescription/mainlabel%3D/order%3Ddescending/sort%3Dstart-20date/offset%3D0/format%3Dtable/searchlabel%3D-5BFindings-20List-5D"