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| Quarter | Site | Title | Description | |
|---|---|---|---|---|
| 05000440/FIN-2017002-01 | 2017Q2 | Perry | Failure to Notify the NRC within Eight Hours of a Non -Emergency Event that Could Have Prevented the Fulfillment of Multiple Safety Functions | Severity Level IV. The inspectors identified a Severity Level IV Non- Cited Violation (NCV) of Title 10 of the Code of Federal Regulations (10 CFR) 50.72(b)(3)(v)(A) and (D), Immediate Notification Requirements for Operating Nuclear Power Reactors, for the licensees failure to report an event to the NRC within eight hours that at the time of discovery could have prevented the fulfillment of a safety function. Specifically, the licensee did not recognize there was a loss of safety function associated with multiple instrumentation functions as a result of a main steam turbine bypass valve opening at 100 percent reactor power. Therefore, the licensee did not make the required non- emergency eight hour report. After the inspectors questioned the licensees conclusion, the licensee recognized there was indeed a loss of safety function and submitted the eight -hour notification report on May 3, 2017. They also and entered this issue into the corrective action program (CAP) as condition report ( CR) 2017 04939, CR 201704868, and CR 201705022. The failure to make an applicable non- emergency eight -hour event notification report within the required time frame was a performance deficiency. The inspectors determined that traditional enforcement was applicable to the issue because it impacted the NRCs regulatory process. In accordance with Section 2.2.2.d, and consistent with the examples included in Section 6.9.d.9 of the NRC Enforcement Policy, this violation was screened as a Severity Level IV violation that was more than minor. In accordance with Inspection Manual Chapter 0612, because this violation involved traditional enforcement and does not have an associated finding that would be considered more- than -minor, a cross-cutting aspect was not assigned to this violation. |
| 05000440/FIN-2017002-02 | 2017Q2 | Perry | Implementation of Enforcement Guidance Memorandum 11003, Revision 3 | From March 17, 2017, to March 24, 2017, Perry Nuclear Power Plant (PNPP) performed Operations with the Potential to Drain the Reactor Vessel (OPDRV) while in Mode 5 without an operable primary and secondary containment. An OPDRV is an activity that could result in the draining or siphoning of the reactor pressure vessel water level below the top of fuel, without crediting the use of mitigating measures to terminate the uncovering of fuel. Secondary containment was required by TS 3.6.4.1 to be operable during OPDRVs. Primary containment was required by TS 3.6.1.10 to be operable during OPDRVS. The required action for these specifications was to suspend OPDRV operations. Therefore, entering the OPDRV without establishing primary and secondary containment integrity was considered a condition prohibited by TS as defined by 10 CFR 50.73(a)(2)(i)(B).The NRC issued Enforcement Guidance Memorandum (EGM) 11003, Revision 3, on January 15, 2016, to provide guidance on how to disposition boiling water reactor licensee noncompliance with TS containment requirements during OPDRV operations. The NRC considers enforcement discretion related to secondary containment operability during Mode 5 OPDRV activities appropriate because the associated interim actions necessary to receive the discretion ensure an adequate level of safety by requiring licensees immediate actions to (1) adhere to the NRC plain language meaning of OPDRV activities; (2) meet the requirements which specify the minimum makeup flow rate and water inventory based on OPDRV activities with long drain down times; (3) ensure that adequate defense in depth is maintained to minimize the potential for the release of fission products with secondary containment not operable by (a) monitoring RPV level to identify the onset of a loss of inventory event, (b) maintaining the capability to isolate the potential leakage paths, (c) prohibiting Mode 4 (cold shutdown) OPDRV activities, and (d) prohibiting movement of irradiated fuel with the spent fuel storage pool gates removed in Mode 5; and (4) ensure that licensees follow all other Mode 5 TS requirements for OPDRV activities.The inspectors reviewed licensee event report (LER) 201700100 for potential performance deficiencies and/or violations of regulatory requirements. The inspectors also reviewed the stations implementation of the EGM during OPDRVs:The inspectors observed that the OPDRV activities were logged in the control room narrative logs, the log entry appropriately recorded the standby source of makeup water designated for the evolutions, and that defense in-depth criteria were in place.The inspectors noted that the reactor vessel water level was maintained at least 22 feet and 9 inches over the top of the reactor pressure vessel flange as required by TS 3.9.6. The inspectors also verified that at least one safety-related pump was the standby source of makeup designated in the control room narrative logs for the evolutions. The inspectors confirmed that the worst case estimated time to drain the reactor cavity to the reactor pressure vessel flange was greater than 24 hours.The inspectors reviewed Engineering Change documents which calculated the time to drain down during these activities and the feasibility of pre-planned actions the station would take to isolate potential leakage paths during these periods of time. The inspectors verified that the OPDRVs were not conducted in Mode 4 and that the licensee did not move irradiated fuel during the OPDRVs. The inspectors noted that PNPP had in place a contingency plan for isolating the potential leakage path and verified that two independent means of measuring reactor pressure vessel water level were available for identifying the onset of loss of inventory events.The inspectors verified that all other TS requirements were met during the March 17, 2017, to March 24 2017, OPDRVs with primary and secondary containment inoperable.Technical Specification 3.6.4.1 required, in part, that secondary containment shall be operable during OPDRV. Technical Specification 3.6.4.1, Condition C, required the licensee to initiate action to suspend OPDRV immediately when secondary containment is inoperable. Technical specification 3.6.1.10 required, in part, that primary containment shall be operable during OPDRV. Technical specification 3.6.1.10, Condition A, required the licensee initiate action to suspend OPDRV immediately when primary containment is inoperable. From March 17, 2017, to March 24, 2017, PNPP performed OPDRV activities while in Mode 5 without an operable primary or secondary containment. Specifically, the station performed the following OPDRV activities without an operable primary or secondary containment:draining of reactor recirculation loop B; replacement of 18 control rod drive mechanisms (unbolt and install);replacement of six instrument dry tubes;replacement of reactor recirculation pump B seal;replacement of reactor recirculation loop B flow control valve actuator;plugging of drain line appendages on reactor recirculation pump B; andlocal leak rate testing of the reactor water cleanup suction line containment isolation valves.The failure to perform OPDRV activities with operable primary and secondary containments is a violation of TS 3.6.1.10 and TS 3.6.4.1. Because the violation occurred during the discretion period described in EGM 11003, Revision 3, the NRC is exercising enforcement discretion in accordance with Section 3.5, Violations Involving Special Circumstances, of the NRC Enforcement Policy and, therefore, will not issue enforcement action for this violation.In accordance with EGM 11003, Revision 3, each licensee that receives discretion must submit a license amendment request within 12 months of the NRC staffs publication in the Federal Register of the notice of availability for a generic change to the standard TS to provide more clarity to the term OPDRV. The inspectors observed thatPNPP is tracking the need to submit a license amendment request as commitment PYL1712101.This LER is closed. This inspection constituted one event follow-up sample as defined in IP 7115305. |
| 05000445/FIN-2007003-01 | 2007Q2 | Comanche Peak | Residual Heat Removal Heat Exchangers Meet Design Safety Function | An unresolved item was identified regarding inadequate design control measures for verifying the adequacy of the safety-related RHR system heat exchangers. The licensee stated that the RHR heat exchangers were not inspected and cleaned, due to ALARA dose consideration. The licensee also stated that the heat exchangers were not tested. Calculation RXE-LA-CPX/0-020, RHR Cooldown Calculations, and Calculation Number ME-CA-0229-2188, Component Cooling Water Heat Exchanger Fouling Factor Analysis, were used by CPSES to determine if the RHR heat exchanger would meet its design basis. The calculations only established an overall component cooling water (CCW) heat exchanger fouling factor and the allowable fouling for continued operations. This issue is unresolved for both significance and enforcement, since additional technical review by NRC was needed to assess this issue. Description: The inspectors reviewed Calculation RXE-LA-CPX/0-020, RHR Cooldown Calculations, Revision 9, which was prepared to demonstrate the RHR cooldown requirements could be met under various conditions. The licensee assumed an overall fouling factor for the CCW heat exchanger. In addition, the licensee used their computer code Cooldown program to determine the performance of the RHR heat exchanger under various operating conditions. The team reviewed the calculation and noted that many assumptions were used. The assumptions included CCW heat exchanger flow rate through the heat exchanger tubes, and an assumed CCW fouling -10- Enclosure factor. The CCW flow rate was 7604 gpm/train, which was about the same as the design basis flow rate of 7600 gpm/train. The inspectors noted that if the assumptions made were changed, the results of the calculation could vary. The inspectors reviewed Calculation ME-CA-0229-2188, Component Cooling Water Heat Exchanger Fouling Factor Analysis, Revision 6, which was used by CPSES personnel to determine if the RHR heat exchanger would meet its design basis by determining algorithms necessary to calculate an overall CCW heat exchanger fouling factor and the allowable fouling or margin for continued operation. The fouling factor for the CCW heat exchanger was determined by using recorded temperatures for the inlet and outlet of the CCW heat exchanger and the inlet and outlet temperatures of the safety-related station service water heat exchanger. In addition, the station service water system flow was measured. However, the inspectors noted the calculation stated that instrument uncertainties were not considered in the calculation. The inspectors noted that the instrument uncertainties could cause a large change in the calculation results which could make the results of the calculation using no instrument uncertainties meaningless. In order to complete the review of the RHR heat exchangers, the inspectors request the following information: The margin for the heat transfer rate is needed. The margin consists of the vendor determined heat transfer rate (BTU/hr) at the licensees design basis conditions for the supplied heat exchangers, and the required design basis heat transfer rate for the plant. Instrument uncertainties are required for Calculation ME-CA-0229-2188 in order to determine the worst case fouling factor for the CCW heat exchanger. Information should be supplied to the inspectors concerning the licensees computer code Cooldown and if it has been verified and validated. Analysis: At the time of writing, CPSES had not demonstrated that the RHR heat exchangers would meet their safety function. This issue is potentially more than minor because it could affect the Mitigating Systems Cornerstone objective by causing the safety-related RHR system to not transfer sufficient heat to the CCW system to support the safety-related systems. The licensee issued Smart Form SMF-2007-001669-00, dated May 17, 2007, to determine what monitoring or testing should be performed on the RHR heat exchangers. The licensee stated that the RHR heat exchangers were operable due to clean water in both the RHR and CCW closed system loops. Enforcement: Part 50 of Title 10 of the Code of Federal Regulations, Appendix B, Criterion III, Design Control, requires, in part, that design control measures shall provide for verifying or checking the adequacy of the design, such as by the performance of design reviews, by the use of alternative or simplified calculation methods, or by performance of a suitable testing program. Additional review by NRC is needed to determine if the RHR heat exchangers would meet their design safety -11- Enclosure function. Therefore, this item will be treated as an unresolved item pending additional review of material to determine if the RHR heat exchangers will meet their safety function: URI 05000445;446/2007003-01, Residual heat removal heat exchangers meet design safety function. |
| 05000445/FIN-2008004-01 | 2008Q3 | Comanche Peak | Failure to Control Transient Combustibles | The inspectors identified a noncited violation of Technical Specification 5.4.1.d for the licensees failure to obtain an approved transient combustible permit before introducing transient combustibles into plant areas. As a result, the licensee placed undocumented and unanalyzed transient combustibles in the plant without compensatory measures on five different occasions. The licensee entered the finding into their corrective action program for resolution. This finding was more than minor because it affected the protection against external factors attribute of the initiating events cornerstone, and it directly affected the cornerstone objective to limit the likelihood of those events that upset plant stability and challenge critical safety functions during shutdown as well as power operations. Using NRC Inspection Manual Chapter 0609, Appendix F, Fire Protection Significance Determination Process, Phase 1 worksheet, the finding was determined to have very low safety significance because the condition represented a low degradation of fire prevention and administrative controls and the amount of combustibles was within the combustible loading calculations. The cause of the finding was related to the Human Performance crosscutting component of Work Practices, in that, the licensee failed to effectively communicate expectations, and that personnel failed to follow procedures (H4.b) (Section 1R05). |
| 05000445/FIN-2008004-02 | 2008Q3 | Comanche Peak | Failure to Follow Diesel Generator Test Procedure | A self-revealing noncited violation of Technical Specification 5.4.1.a was reviewed for the failure of the licensee to follow the procedure for testing the emergency diesel generator. As a result, a cylinder indicator cock was left open and cylinder performance was affected. The licensee entered the finding into their corrective action program for resolution. The finding was more than minor because it was associated with the availability/reliability of equipment performance attribute of the mitigating systems cornerstone, and it directly affected the cornerstone objective to ensure the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences. Using NRC Inspection Manual Chapter 0609, Attachment 4, Phase 1 Initial Characterization and Screening of Findings, the finding screened as having very low safety significance because it resulted in a minimal degradation of a diesel generator cylinder. The cause of this finding was related to the Human Performance crosscutting component of resources, in that, the licensee failed to provide adequate equipment to close the indicator cock (H2.d) (Section 1R15). |
| 05000445/FIN-2008004-03 | 2008Q3 | Comanche Peak | Unevaluated Temporary Modification of Containment Isolation Valve | Green. The inspectors identified a noncited violation of Technical Specification 5.4.1.a for the licensees failure to control a fire hose that was used to redirect the discharge of a vent chill water relief valve, which is also a containment isolation valve. As a result, a hose was left on the discharge piping at various times for approximately 10 years without documentation or evaluation. The hose affected the relief valve, in that, operators could not directly observe leakage from the valve. In addition, the hose created a backpressure on the valve that increased its lift setpoint, therefore, potentially affecting the containment penetration integrity. The licensee entered the finding into their corrective action program for resolution. This finding was greater than minor because it was similar to NRC Inspection Manual Chapter 0612, Appendix E, Examples of Minor Issues, Example 4.a, and met the not minor if criteria because the licensee routinely failed to perform evaluations on this issue, and the inspectors determined that the safety-related equipment was adversely affected. Using NRC Inspection Manual Chapter 0609, Attachment 4, Phase 1 - Initial Characterization and Screening of Findings, the inspectors determined that the issue was of very low safety significance because the finding did not result in an actual open pathway of the reactor containment. The cause of this finding was related to the Human Performance crosscutting component of Work Practices, in that, the licensee failed to define and effectively communicate expectations regarding procedural compliance and personnel failed to follow procedures (H4.b) (Section 1R18). |
| 05000445/FIN-2008004-04 | 2008Q3 | Comanche Peak | Failure to Ensure Roll-up Fire Doors Complied with Fire Code | The inspectors identified a noncited violation of License Condition 2.G because the licensee failed to ensure that two fire-rated roll-up doors complied with the mounting requirements in National Fire Protection Association (NFPA) 80-1977. Specifically, during original construction, the licensee used bolts with a diameter less than the required 3/8-inch. The licensee entered this finding into their corrective action program for resolution as Smartform SMF-2008-001637. Failure to meet the mounting requirements of NFPA 80-1977 for fire-rated roll-up doors is a performance deficiency. The inspectors determined this deficiency was more than minor because it was similar to the more than minor description in Manual Chapter 0612, Appendix E, Example 3.g. This finding affected the mitigating systems cornerstone. This fire confinement finding was assigned a Moderate A degradation rating because the fire-rated roll-up door had improperly installed fire door hardware. Using NRC Inspection Manual Chapter 0609, Appendix F, Fire Protection Significance Determination Process, Phase 1, Step 1.3.2, Question 5, the exposed fire area contained no potential damage targets closer than 20 feet (i.e., passive barrier) to the exposing fire area that would result in a demand for safe shutdown and the fire barrier would remain functional for at least 20 minutes. Therefore, the degraded fire-rated roll-up doors had very low risk significance (Section 4OA5). |
| 05000445/FIN-2008007-01 | 2008Q1 | Comanche Peak | Failure to Correctly Test the Primary Plant Ventilation System (Section 2PS1) | On February 26, 2008, the team observed in-place filter testing on the primary plant ventilation system. The primary plant ventilation exhaust filter (Unit X-15) contained two banks of high efficiency particulate air (HEPA) filters, separated by charcoal adsorbers. The testing was performed by licensee personnel and generally followed the the guidance in Regulatory Guide 1.52 and ANSI/ASME N510 1980, in which the HEPA filters are tested by injecting dioctyl phthalate (DOP) aerosol upstream of the filters with the system fan or an auxiliary blower operating. DOP concentration measurements are made upstream and downstream of the HEPA filters and percent penetration is calculated from the ratio of DOP concentrations in the filtered air (downstream reading) and the unfiltered air (upstream reading). The penetration must be less than one percent for the primary plant ventilation system. The team identified problems with the implementation of the licensees testing program which could cause a failure to collect representative DOP (particulate) samples and, therefore, non-conservative test results. The licensee did not use sampling nozzles, pitot tubes, or similar devices to ensure particulates were collected from the air stream. Instead, the licensee used flexible plastic, small-diameter tubing (0.19-inch inside diameter) inserted into larger hoses or ducts. During the test of the first bank of HEPA filters, a manifold was used for sampling the downstream air. The manifold was attached to a hose (1-inch inside diameter) which, in turn, was attached to a vacuum cleaner (flow rate unknown by the licensee). One end of a flexible tube was inserted into the hose between the point where exited the air cleaning unit and the vacuum cleaner. The other end was attached to a penetrometer equipped with a light-scattering aerosol photometer. There was no sampling nozzle and no means of ensuring the end of the tubing was pointed into the air stream. Consequently, there was no means of ensuring the air sample collected was representative of actual DOP concentration in hose. The engineer performing the test stated he had been careful to ensure the tubing was pointed into the air stream. However, the team could not verify this because the duct tape used to secure the tubing into the hose prevented observation. Additionally, the team noted the surveillance test procedure (PPT-SX-7509A, Revision 0) provided no detailed guidance for setting up the test equipment correctly and consistently. This was dependent on the knowledge of the individual conducting the testing. To measure the downstream concentration after the second bank of HEPA filters, the licensee inserted one end of a piece of a flexible plastic tube to approximately the center of a large duct (approximately 3.2 feet inside diameter) in which the air velocity was approximately 1700 feet per minute. The other end was attached to the penetrometer. Without a rigid sampling nozzle or similar device, the flexible tube likely was pointing in the direction of the air flow, rather than into it. Consequently, the penetrometer sampling pump had to capture particles traveling at the speed of the air stream and change their direction as much as 180 degrees in order to collect and count them. The failure to capture and count DOP particles downstream of the HEPA filters results in nonconservative test results and could give a false indication the filters had successfully passed the acceptance criteria. Engineering representatives stated this method had been established by vendor personnel before commercial operation and had been used by licensee personnel since that time. Further, the licensee believed it could confirm through testing the equipment configured this way provided representative test results; however it would not be able to until May 2008, after the Unit 2 refueling outage Therefore, this item will remain unresolved, pending the results of further testing by the licensee |
| 05000445/FIN-2009002-01 | 2009Q1 | Comanche Peak | Failure to Remove Debris from Rooftop Causes Potential Missle Hazard (Section 1R13) | The inspectors identified a finding for the failure to follow housekeeping guidance in Procedure STA-607, Housekeeping Control, Revision 19. Specifically, the licensee failed to remove several pieces of thin scrap sheet steel approximately five feet long and one foot wide from the Unit 1 diesel generator building roof following maintenance. As a result, the material could have affected the offsite power supply to safety-related electrical busses if high winds carried it on to nearby transmission lines. The inspectors determined that the material was on the rooftop during periods of severe weather. The licensee entered the finding into their corrective action program for resolution as Smart Form SMF-2008-004000. The finding was more than minor because it was associated with the initiating events cornerstone attribute of protection against external factors and affected the cornerstone objective, in that, it increased the likelihood of an event that would upset plant stability and challenge critical safety functions during shutdown as well as power operations. Using NRC Inspection Manual Chapter 0609, Attachment 4, Phase 1- Initial Characterization and Screening of Findings, the finding screened as very low safety significance (Green) because the condition did not contribute to both the likelihood of a reactor trip and the likelihood that mitigation equipment would not be available. The cause of this finding was related to the Human Performance crosscutting component of work control, in that, the licensee failed to appropriately coordinate work activities (H3.b) (Section 1R13) |
| 05000445/FIN-2009002-02 | 2009Q1 | Comanche Peak | Failure to Initiate a Smart Form for Damage to Safety-Related Breakers (Section 1R15) | The inspectors identified a noncited violation of 10 CFR Part 50, Appendix B, Criterion V, for failure to follow procedures that require initiating a Smart Form for damage to safety-related equipment. The licensee discovered a bent shutter pin in the internal racking mechanism of a safety-related circuit breaker during maintenance. However, because the condition was not entered into the Smart Form database, the licensee failed to correct the cause of the condition and formally evaluate the impact of the condition on all of the associated 480 volt breakers. The licensee entered the finding into their corrective action program as Smart Form SMF-2009-000095. The finding was more than minor because if the licensee continues to fail to document damage to safety-related equipment in a Smart Form, there is potential that it could lead to a more significant safety concern in that the damage will not be evaluated and corrected. Using NRC Inspection Manual Chapter 0609, Attachment 4, Phase 1- Initial Characterization and Screening of Findings, the finding screened as very low safety significance (Green) because the condition did not result in the inoperability of safety-related breakers when they were required to be operable. The cause of this finding was related to the Problem Identification and Resolution crosscutting component of the corrective action program, in that, the licensee failed to enter the issue into the Smart Form database (P1.a) (Section 1R15) |
| 05000445/FIN-2009002-03 | 2009Q1 | Comanche Peak | Failure to Follow Procedure Causes Unplanned Load Change (Section 4OA3.2) | A self-revealing noncited violation of Technical Specification 5.4.1.a was identified for the failure of operators to follow procedural requirements when reducing turbine load. As a result, operators transposed two digits and inadvertently reduced turbine load from 1273.7 megawatts to 1237.5 megawatts instead of 1273.5 megawatts. In response to the transient, the control rods automatically inserted approximately 17 steps to maintain programmed reactor coolant system temperature. The licensee entered the finding into their corrective action program as Smart Form SMF-2009-000028. The finding was more than minor because it was associated with the human performance attribute of the initiating events cornerstone, and directly affected the cornerstone objective to limit the likelihood of those events that upset plant stability during power operations. Using Manual Chapter 0609, Attachment 4, Phase 1 - Initial Screening and Characterization of Findings, the finding was determined to have very low safety significance (Green) because it did not contribute to the likelihood of mitigating equipment being unavailable. The cause of the finding was related to the Human Performance crosscutting component of work practices for the failure to use self and peer checking techniques (H4.a) (Section 4OA3.2). |
| 05000445/FIN-2017001-01 | 2017Q1 | Comanche Peak | Failure to Maintain B.5.b Equipment in a State of Readiness to Support Mitigation Strategies | Green. The inspectors identified a non-cited violation of 10 CFR 50.54(hh)(2), Conditions of Licenses, involving the licensees failure to maintain available equipment needed to implement mitigating strategies to provide makeup to steam generators following loss of large areas of the plant due to explosions or fire. Specifically, the licensee failed to maintain available a portable alternate mitigation equipment pump related to the steam generator makeup strategy. As an immediate corrective action the licensee put temporary heaters in place for the alternate mitigation equipment pump to ensure the equipment was stored at temperatures greater than 32 degrees Fahrenheit pending further evaluation. The licensee entered this issue into their corrective action program as Condition Report CR-2016-010832. The failure to maintain all necessary equipment available to implement mitigating strategies as required by regulations and conditions of the operating license was a performance deficiency. The performance deficiency was more than minor, and therefore a finding, because it was associated with the design control attribute of the Mitigating Systems cornerstone and affected the cornerstone objective to ensure the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences. Using Inspection Manual Chapter 0609, Appendix L, B.5.b Significance Determination Process, dated December 24, 2009, the inspectors determined the finding was of very low safety significance (Green) because it resulted in an unrecoverable unavailability of an individual mitigating strategy but did not result in multiple unavailable mitigating strategies, or loss of all on-site, self-powered, portable pumping capability. The inspectors did not assign a cross-cutting aspect because the performance deficiency was not reflective of present performance. |
| 05000445/FIN-2017001-02 | 2017Q1 | Comanche Peak | Failure to Evaluate Heat Loads on Control Room Air Conditioning System | Green. The inspectors identified a non-cited violation of 10 CFR 50, Appendix B, Criterion III, Design Control, for the licensees failure to properly evaluate heat loads on the control room air conditioning system. Specifically, the licensee used a non-conservative assumption for the number of persons in the control room envelope when calculating the required capacity of the system. The licensee had assumed there would only be six personnel in the technical support center (which is included in the control room envelope) during a design basis event. However, the emergency plan nominally staffed the technical support center with 25 station personnel, and an additional five NRC personnel. The licensee implemented immediate corrective actions by entering the issues into the corrective action program for resolution and performed an operability determination for the identified degraded condition. The licensee entered this issue into their corrective action program as Condition Report CR-2017-000744. The failure to evaluate heat loads to determine the required system capacity was a performance deficiency. The performance deficiency was more than minor, and therefore a finding, because it was associated with the design control attribute of the Mitigating Systems Cornerstone and affected the cornerstone objective to ensure availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences. Using Inspection Manual Chapter 0609, Attachment 04, Initial Characterization of Findings, dated October 7, 2016, and Inspection Manual Chapter 0609, Appendix A, Significance Determination Process for Findings At-Power, Exhibit 2, Mitigating Systems Screening Questions, the inspectors determined the finding was of very low safety significance (Green) because the finding: (1) was not a deficiency affecting the design and qualification of a mitigating structure, system, or component, and did not result in a loss of operability or functionality, (2) did not represent a loss of system and/or function, (3) did not represent an actual loss of function of at least a single train for longer than its allowed outage time, or two separate safety systems out-of-service for longer than their technical specification allowed outage time, and (4) does not represent an actual loss of function of one or more non-technical specification trains of equipment designated as high safety-significant for greater than 24 hours in accordance with the licensees maintenance rule program. The inspectors determined that no cross-cutting aspect was assigned because the performance deficiency was not reflective of present performance. |
| 05000445/FIN-2017001-03 | 2017Q1 | Comanche Peak | Use of Non-Design Fouling Factor for Component Cooling Water Heat Exchanger in Station Service Water Tornado Missile Calculation | Green. The inspectors identified a non-cited violation of 10 CFR Part 50, Appendix B, Criterion III, Design Control, involving the failure to use the design fouling factor for the component cooling water heat exchanger in a design basis calculation evaluating a tornado missile strike of station service water system piping. The licensee implemented immediate corrective actions by entering the issues into the corrective action program for resolution and performed an operability determination for the identified degraded conditions. The licensee entered this issue into their corrective action program as Issue Report IR-2017-001465. The inspectors determined that the failure to use the design fouling factor for the component cooling water heat exchanger in the tornado missile analysis of the station service water system discharge piping was a performance deficiency. This finding 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 use of a non-conservative heat exchanger fouling factor in a design basis accident analysis resulted in a more restrictive temperature limit (i.e., less than the technical specification allowed value) of the safe shutdown impoundment. In accordance with Inspection Manual Chapter 0609, Appendix A, The Significance Determination Process (SDP) for Findings At-Power, dated June 19, 2012, Exhibit 2, Mitigating Systems Screening Questions, the issue screened as having very low safety significance (Green) because it was a design or qualification deficiency that (1) did not represent a loss of operability or functionality; (2) did not represent an actual loss of safety function of the system or train; (3) did not result in the loss of one or more trains of non-technical specification equipment; and (4) did not screen as potentially risk-significant due to seismic, flooding, or severe weather. The inspectors determined that this finding did not have a cross-cutting aspect because the most significant contributor to the performance deficiency did not reflect current licensee performance. Specifically, the licensee performed the calculation in 1988, therefore, the performance deficiency occurred outside of the nominal three-year period for present performance. |
| 05000445/FIN-2017001-04 | 2017Q1 | Comanche Peak | Failure to Promptly Correct a Condition Adverse to Quality | Green. The inspectors identified a non-cited violation of 10 CFR 50, Appendix B, Criterion XVI, Corrective Action, associated with the licensees failure to take timely corrective actions for a previously identified condition adverse to quality. Specifically, the licensee failed to verify the adequacy of the design of the Unit 1 120 VAC vital bus inverter 1PC1 with respect to use of alternate AC power to the inverter. The 120 VAC calculation did not properly account for low voltage when the buses are supplied from their alternate source. This issue does not represent an immediate safety concern because, following the inspectors identification, the licensee performed an operability evaluation which established a reasonable expectation of operability. The licensee implemented immediate corrective actions by entering the issues into the corrective action program for resolution and performed an operability determination for the identified degraded conditions. The licensee entered this issue into their corrective action program as CR-2017-001296. The licensees failure to take timely and adequate corrective actions to correct a condition adverse to quality was a performance deficiency. The performance deficiency is more than minor, and therefore a finding, because it is associated with the equipment performance attribute of the Mitigating Systems Cornerstone and affected the cornerstone objective to ensure availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences. Specifically, the failure to correct the low voltage susceptibility resulted in delayed restoration of a bus following the failure of the swing inverter to sync. Using Inspection Manual Chapter 0609, Attachment 04, Initial Characterization of Findings, dated October 7, 2016, and Inspection Manual Chapter 0609, Appendix A, Significance Determination Process for Findings At-Power, Exhibit 2, Mitigating Systems Screening Questions, the inspectors determined the finding was of very low safety significance (Green) because the finding: (1) was not a deficiency affecting the design and qualification of a mitigating structure, system, or component, and did not result in a loss of operability or functionality, (2) did not represent a loss of system and/or function, (3) did not represent an actual loss of function of at least a single train for longer than its allowed outage time, or two separate safety systems out-of-service for longer than their technical specification allowed outage time, and (4) does not represent an actual loss of function of one or more non-technical specification trains of equipment designated as high safety-significant for greater than 24 hours in accordance with the licensees maintenance rule program. The finding has a human performance cross-cutting aspect associated with resources, in that, the licensee failed to ensure that resources were adequate to support nuclear safety (H.1). |
| 05000445/FIN-2017001-05 | 2017Q1 | Comanche Peak | Licensee-Identified Violation | Title 10 CFR 50.54(q)(2) requires, in part, that licensees shall follow and maintain the effectiveness of an emergency plan that meets the planning standards of 10 CFR 50.47(b). Title 10 CFR 50.47(b)(2) requires, in part, that timely augmentation of response capabilities be available. The licensees emergency plan provides for the ability to augment response capabilities by use of a system to callout additional personnel to fill their emergency response organization (ERO) staffing requirements for declared emergencies. Contrary to the above, from January 5, 2017 until January 17, 2017, the licensee failed to ensure timely augmentation of response capabilities was available. Specifically, on January 5, 2017, the licensees corporate security office removed 32 members of the ERO from the licensees callout system, including eight personnel assigned to minimum staffing positions. The licensee identified the issue when, following an inadvertent actuation of the callout system on January 16, 2017, they discovered that multiple personnel were not called. The licensee restored all required personnel to the callout system on January 17, 2017. The violation is more than minor because it affected the ERO readiness attribute of the Emergency Preparedness cornerstone and impacted the cornerstone objective to ensure that the licensee is capable of implementing adequate measures to protect the health and safety of the public in the event of a radiological emergency. Using Inspection Manual Chapter 0609, Attachment 04, Initial Characterization of Findings, and Inspection Manual Chapter 0609, Appendix B, Emergency Preparedness Significance Determination Process, the inspector determined that the violation is of very low safety significance (Green) because the finding represented a failure to comply with planning standard (b)(2), and, using table 5.2-1, was screened as a Green finding because the deficiency did not cause more than one required ERO functional area to not be filled. The violation was entered into the licensees corrective action program as CR-2017-001524. |
| 05000446/FIN-2017001-06 | 2017Q1 | Comanche Peak | Licensee-Identified Violation | Comanche Peak Unit 2, Operating License NPF-89, Condition 2.G, Fire Protection, requires, in part, that the licensee implement and maintain in effect all provisions of the approved fire protection program as described in the Final Safety Analysis Report through Amendment 87, and as approved in the Safety Evaluation Report and its supplements through Supplement 27. The stations approved fire protection program includes Fire Protection Report, Revision 29, Section 3.1 which requires, in part, that when fire detection equipment located inside of the containment building is inoperable then hourly monitoring of air temperature is performed as a compensatory measure. Contrary to the above, on November 22, 2016, licensee personnel identified that compensatory measures implemented for a failed detection system in the Unit 2 containment had not been implemented. The licensee had implemented a compensatory measure on December 3, 2015, to monitor containment temperature in the Unit 2 containment hourly due to a failed thermistor strip. On November 17, 2016, the licensee stopped monitoring temperature after restoring a different component to service. The licensee subsequently realized that the compensatory measure was still required and reinstated it on November 22, 2016. The violation is more than minor because it affected the protection against external events attribute of the Mitigating Systems cornerstone and affected the cornerstone objective to ensure the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences. Using Inspection Manual Chapter 0609, Attachment 04, Initial Characterization of Findings, and Inspection Manual Chapter 0609, Appendix F, Fire Protection Significance Determination Process, the inspector determined that the violation is of very low safety significance (Green) because the finding did not affect the ability of either unit to achieve safe shutdown. The violation was entered into the licensees corrective action program as Condition Report CR-2016-009888. |
| 05000458/FIN-2009002-01 | 2009Q1 | River Bend | Inadequate Risk Assessment While the Control Building Chilled Water System was Removed from Service | The inspectors identified a Green noncited violation of 10 CFR 50.65(a)(4) involving the failure of operators to perform an adequate risk assessment while the Division 1 control building chilled water was unavailable. Specifically, the inspectors identified that licensee personnel non-conservatively evaluated the on-line risk as Green instead of Yellow. This resulted in an unrecognized increase in the level of risk as determined by Entergys probabilistic safety analysis evaluation. The licensee entered this issue into their corrective action program as Condition Report CR-RBS-2009-0862. Using Inspection Manual Chapter 0612, Appendix E, Section 3, Item 7(e), the finding is more than minor because the licensees risk assessment had errors and incorrect assumptions regarding the unavailability of mitigating systems that put the plant in a higher risk category. Using Inspection Manual Chapter 0609, Significance Determination Process, Appendix K, Maintenance Risk Assessment and Risk Management Significance Determination Process, the finding is determined to have very low safety significance because the incremental core damage probability deficit for the affected time period is less than 1.0E-6. This finding has a crosscutting aspect in the area of human performance component for work practices because Entergy personnel did not effectively follow procedures (H.4(b)) (Section 1R13) |
| 05000458/FIN-2009002-02 | 2009Q1 | River Bend | Licensee-Identified Violation | License Condition 2.C(10) specifies that the licensee shall comply with the requirements of the fire protection program as specified in Attachment 4 to the license. The Final Safety Analysis Report, Section 9B.4.7, specifies, in part, \"Fire protection features shall be capable of limiting fire damage so that one train of systems necessary to achieve and maintain hot shutdown conditions from either the control room or emergency control station(s) is free of fire damage.\" Contrary to the above, on January 6, 2006, the licensee determined that they failed to ensure that Valve E51-MOVF063, which was required to achieve hot shutdown, remained free of fire damage under all conditions. The licensee promptly implemented appropriate compensatory measures and initiated plans to correct the deficiency. The licensee documented this deficiency in Condition Report 2006-00046 and planned to correct the deficiency in 2009. This finding had very low safety significance (Green). This item is further discussed in Section 4OA3.1 |
| 05000458/FIN-2009002-03 | 2009Q1 | River Bend | Licensee-Identified Violation | License Condition 2.C(10) specifies that the licensee shall comply with the requirements of the fire protection program as specified in Attachment 4 to the license. The Updated Safety Analysis Report, Section 9B.4.7, specifies, in part, Fire protection features shall be capable of limiting fire damage so that one train of systems necessary to achieve and maintain hot shutdown conditions from either the control room or emergency control station(s) is free of fire damage. Contrary to the above, on May 21, 2007, the licensee determined that they failed to ensure that the Division 1 emergency diesel generator, which was required to achieve hot shutdown, remained operable, hence, free of fire damage under all conditions. Specifically, if service water became unavailable because of a spurious actuation (e.g. valve closure) coincident with a loss of offsite power, the emergency diesel generator could potentially fail prior to transfer of control to the remote shutdown panel. The licensee promptly implemented appropriate compensatory measures and initiated plans to correct the deficiency. The licensee documented this deficiency in Condition Report 2007-02102 and planned to correct the deficiency in 2009. This finding had very low safety significance (Green). This item is further discussed in Section 4OA3.2 |
| 05000458/FIN-2009002-04 | 2009Q1 | River Bend | Licensee-Identified Violation | A licensee is required by 10 CFR 50.54(q) to follow and maintain an emergency plan that meets the requirements of 10 CFR 50.47(b); 10 CFR 50.47(b)(15) requires that emergency response training be provided to those who may be called upon during an emergency; Appendix E to 10 CFR 50, IV(F)(1) requires that emergency responders, including control room personnel responsible for accident assessment and radiological monitoring teams, receive initial training and periodic retraining. Contrary to this, licensee personnel responsible for accident assessment and radiological monitoring teams did not receive required periodic retraining. Specifically, six radiation protection technicians and one chemistry technician stood eleven watches between January and April 2008 in required on-shift emergency response organization positions without having received required annual retraining prior to December 31, 2007. This issue was identified in the licensee=s corrective action program as Condition Report CR-RBS-2008-02661. This finding is of very low safety significance because it was a failure to comply with regulatory requirements, the finding was associated with a 50.47(b) planning standard, the affected planning standard was not risk significant as defined in Inspection Manual Chapter 0609, Appendix B, Section 2, and the finding was not a loss of the emergency response function because the licensee had a functional training program and other on-shift personnel having the same emergency response duties received the training. This item is further discussed in Section 4OA2.1 |
| 05000458/FIN-2009002-05 | 2009Q1 | River Bend | Licensee-Identified Violation | Technical Specification 3.1.7 requires, in part, that two standby liquid control subsystems shall be operable. Contrary to the technical specification requirement, from March 14, 2003, to October 28, 2008, the standby liquid control system was not capable of performing its design safety function to limit suppression pool particulate iodine to evolve into airborne iodine. In accordance with NRC Inspection Manual Chapter 0612, Appendix B, \"Issue Screening,\" the inspectors determined that the failure to drain the test tank, maintaining the seismically qualified configuration, was a licensee performance deficiency. The issue was more than minor because it was similar to Example 3.a in Manual Chapter 0612, Appendix E, and it met the not minor if requirement because changes were required in the procedure to correctly resolve the seismic concerns. The inspectors evaluated the issue using the Significance Determination Process (SDP) Phase 1 Screening Worksheet for the Initiating Events, Mitigating Systems, and Barriers Cornerstones provided in Manual Chapter 0609, Attachment 4, \"Phase 1 Initial Screening and Characterization of Findings. The inspectors determined that this finding affected the Mitigating Systems Cornerstone and that the finding screened as potentially risk significant to a seismic initiating event because assuming that the tank completely failed, affecting the nearby pumps and electrical equipment, the loss would degrade both trains of the multi-train standby liquid control system. Therefore, a Phase 3 analysis was conducted by a senior reactor analyst in accordance with Manual Chapter 0609, Appendix A, Determining the Significance of Reactor Inspection Findings for At-Power Situations. In accordance with Manual Chapter 0609, Appendix A, the analyst performed a Phase 3 assessment of the risk contributions from a seismic initiator using insights and/or values provided by the Risk Assessment of Operational Events Handbook, Volume 2, External Events. Assumptions: To evaluate the change in risk caused by this performance deficiency, the analyst made the following assumptions: a. The River Bend Station SPAR model, Revision 3.45 and a spreadsheet evaluation of the River Bend seismic hazard represented appropriate tools for evaluation of the subject finding. b. The standby liquid control system test tank had remained full of water during power operations for approximately 5 years. c. Given Assumption b. the appropriate exposure period is one year, representing the most recent assessment period was used for exposure to this failure. d. The standby liquid control system test tank would only have failed during a seismic event. Therefore only seismic initiators, seismically-induced initiators, and independent failures occurring simultaneously with seismic events were evaluated. e. The failure of the standby liquid control system would affect the core damage frequency if the seismic event occurred simultaneously with an anticipated transient without scram because the failure would impact the systems function to shut down the reactor. f. The failure of the standby liquid control system would affect the core damage frequency if the seismic event also resulted in a loss of coolant accident because the failure would impact the systems function to control suppression pool chemistry. g. The likelihood of a seismic event equal to or larger than 0.5g peak ground acceleration occurring within 24 hours of an independent plant initiator is approximately 4E-10. h. A seismic event smaller than 0.5g peak ground acceleration is not likely to affect plant operations at River Bend Station. i. Given Assumptions g and h, the probability that a seismic event large enough to affect the plant occurs at the same time as an unrelated plant initiator is inconsequential to this analysis. j. The seismic hazard vector for River Bend Station provided in Table 4A-1 of the Risk Assessment of Operation Events Handbook, Volume 2, External Events, Revision 1.01, is appropriate for evaluation of the subject finding. Analysis: In accordance with Assumptions e, f and i, the analyst determined that, for the subject performance deficiency to affect the core damage frequency, a seismic event must either occur at the same time as an anticipated transient without scram, or result in a loss of coolant accident (LOCA). As such, the analyst evaluated the subject performance deficiency by determining each of the following parameters for any seismic event producing a given range of median average spectral acceleration \"a\" (SE(a)): • The frequency of the seismic event SE(a) (eSE(a)); • The probability that a LOCA occurs during the event (PLOCA-SE(a)); • The probability that an independent LOCA occurs (PINIT-SE(a)); and • The probability of an ATWS occurring (PATWS-SE(a)). The frequency of a seismically induced demand on the SLC system (eSLC-SE(a)) can then be quantified as follows: eSLC-SE(a) = eSE(a) * (PLOCA-SE(a) + PINIT-SE(a) + PATWS-SE(a)) Given that each range a was selected by the analyst specifically to be independent of all other ranges, the total frequency of an induced demand, eSLC, can be quantified by summing the eSLC-SE(a) for each range evaluated as follows: 1.0 ACDF = O eSLC-SE(a) a=.05 over the range of SE(a). Results: The resulting value, quantified in a spreadsheet, was 5.4 x 10-7. The analyst noted that this conditional probability is significantly higher than a best estimate because the method used was to assume that the failure of the standby liquid control system was guaranteed following a failure of the test tank and that the failure of the standby liquid control system always resulted in core damage. Both these assumptions are known to be bounding. Therefore, this finding was of very low risk significance. Entergy documented this issue in Condition Report RBS-2008-06244. This item is further discussed in Section 4OA3.3 |
| 05000458/FIN-2013007-04 | 2013Q4 | River Bend | Unresolved Item Associated with the Isolation of the Alternative Shutdown System | The team identified an unresolved item associated with the isolation of post-fire safe shutdown circuitry for control room fire scenarios. Specifically, the team identified that the licensee may not adequately isolate circuitry for the safety relief valves and the main steam isolation valves from the effects of a control room fire. In the event of a fire in the control room, the licensee must ensure control circuitry for equipment credited for post-fire safe shutdown is electrically isolated from the control room so that fire damage could not prevent the ability to achieve and maintain safe shutdown conditions. For valves that are required to close or remain closed for post-fire safe shutdown, the licensee must ensure that control room fires do not prevent the closure of the valves and do not spuriously open the valves once the control room has been isolated and control transferred from the control room to the remote shutdown panel. Example 1: Spurious Opening of the Safety Relief Valves The alternative shutdown procedure provided steps for operators to mitigate the effects of any single spurious actuation or signal resulting from a control room fire that occurred prior to transferring control from the control room to the remote shutdown panel. For the safety relief valves, the procedure directed operators to de-energize two 125 Vdc panels (ENB-PNL02A and ENB-PNL02B) in order to ensure that the 13 non-credited safety relief valves were closed. The three credited safety relief valves were isolated from the control room via the use of transfer switches. The team identified a concern that hot shorts in the control room could cause a spurious actuation that threatened the ability to achieve and maintain safe shutdown conditions. The team noted that the control room cabinets containing the safety relief valves also contained other 125 Vdc circuits that remained energized during an alternative shutdown. The team was concerned that hot shorts from one of these circuits could prevent the closure of a safety relief valve (if spuriously open) or could spuriously open the safety relief valve once the control room was isolated and control transferred from the control room to the remote shutdown panel. The team was also concerned that the safe shutdown analysis did not analyze for one or more safety relief valves remaining open during the plant shutdown. This concern applied to the 13 safety relief valves that did not have control transferred to the remote shutdown panel. In addition, the team noted that circuit failures could spuriously open multiple safety relief valves through the spurious actuation of the automatic depressurization system. The team was concerned that the spurious actuation of the automatic depressurization system could be considered a single spurious actuation or signal that fell within the bounds of the safe shutdown analysis. A similar concern was first identified during the 1997 fire protection functional inspection and documented in Inspection Reports 97-201 and 98-16. Example 2: Spurious Opening of the Main Steam Isolation Valves As noted in the previous example, the alternative shutdown procedure provided steps for operators to mitigate the effects of any single spurious actuation or signal resulting from a control room fire that occurred prior to transferring control from the control room to the remote shutdown panel. For the main steam isolation valves, the procedure directed operators to attempt to close the main steam isolation valves inside the control room and then de-energize the reactor protection system motor generator sets outside the control room. The reactor protection system provides power to the circuitry for the main steam isolation valve solenoids. When the solenoids are de-energized, the main steam isolation valves fail closed. The team identified a concern that hot shorts in the control room could cause spurious actuations that threatened the ability to achieve and maintain safe shutdown conditions. Specifically, the team identified that a portion of the trip logic circuitry was connected in the control room to the portion of the circuitry that energizes the solenoid valve for each main steam isolation valve. The trip logic circuitry was located downstream of where the reactor protection system bus was de-energized, and it did not contain a protective circuit device such as fusing or open contacts that would isolate the trip logic portion of the circuitry from the solenoid valve. The control room cabinet containing the trip logic circuitry also contained other 125 Vdc circuits that remained energized during an alternative shutdown. The team was concerned that hot shorts from these circuits could prevent the closure of the main steam isolation valves or could spuriously open the main steam isolation valves after the reactor protection system motor generator sets were de-energized. The team noted that one main steam isolation valve, either inboard or outboard, must close and remain closed in order to maintain inventory. The licensee entered these issues into the corrective action program as Condition Report CR-RBS-2013-03473. The team determined that additional inspection is required to determine if a performance deficiency exists. This issue of concern is being treated as an Unresolved Item URI 05000458/2013007-04, Unresolved Item Associated with the Isolation of the Alternative Shutdown System. |
| 05000458/FIN-2016007-01 | 2016Q2 | River Bend | Inadequate Loop Flow Test Procedure | The team identified a non-cited violation of License Condition 2.C.(10) for the failure to implement and maintain in effect all provisions of their approved fire protection program. Specifically, the licensees fire protection program surveillance testing procedure for the fire main yard loop did not include appropriate guidance to properly flow test all portions of the underground fire main yard loop to buildings that contained fire safe shutdown equipment. The licensee entered this deficiency into their corrective action program as Condition Report CR-RBS-2016-03212 and initiated actions to correct the procedure and perform the flow testing. The failure to ensure that fire protection program Surveillance Test Procedure STP-251-3700, Fire System Yard Water Suppression Loop Flow Test, Revision 10, included requirements to functionally test all individual underground firewater flow paths to structures that contained fire safe shutdown components was a performance deficiency. The performance deficiency was more than minor because it was associated with the protection against external factors (fire) attribute of the Mitigating Systems Cornerstone and adversely affected the Mitigating Systems Cornerstone objective of ensuring the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences. The finding was screened in accordance with NRC Inspection Manual Chapter 0609, Significance Determination Process, Attachment 4, Initial Characterization of Findings, dated June 19, 2012. The team determined that an Inspection Manual Chapter 0609, Appendix F, Fire Protection Significance Determination Process, dated September 20, 2013, review was required because the finding affected the fire water supply system. Using Inspection Manual Chapter 0609, Appendix F, Attachment 1, Fire Protection Significance Determination Process Worksheet, dated September 20, 2013, the finding was screened as a Green finding of very low safety significance in accordance with Task 1.4.7, Fire Water Supply, Question A. Since the subject fire main yard loops had not been flow tested since initial testing, and nothing caused the licensee to reevaluate the testing procedure, the team determined that this failure did not reflect current performance, and no cross-cutting aspect was assigned. |
| 05000458/FIN-2016007-02 | 2016Q2 | River Bend | Failure to Isolate Control Circuits for Safe Shutdown Equipment From the Effects of a Control Room Fire | The team identified a non-cited violation of License Condition 2.C.(10) for the failure to implement and maintain in effect all provisions of the approved fire protection program. Specifically, the team identified two examples where the licensee failed to isolate control circuits for safe shutdown equipment to ensure independence from the effects of a fire in the control room. As immediate compensatory measures the licensee performed visual inspections of the affected cabinets for unacceptable fire hazards and issued Standing Order 323 to reinforce the need for operators to identify and prevent fire hazards while in the control room. The licensee entered this issue into their corrective action program as Condition Reports CR-RBS-2016-02953 and CR-RBS-2016-03264. The failure to isolate control circuits for safe shutdown equipment from the effects of a control room fire was a performance deficiency. The performance deficiency was more than minor because it was associated with the protection against external events (fire) attribute of the Mitigating Systems Cornerstone and it adversely affected the Mitigating Systems Cornerstone objective of ensuring the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences. The team evaluated this finding using Inspection Manual Chapter 0609, Appendix F, Fire Protection Significance Determination Process, dated September 20, 2013, because it affected the ability to reach and maintain safe shutdown conditions in case of a fire. A senior reactor analyst performed a Phase 3 evaluation to determine the risk significance of this finding since it involved a postulated control room fire that led to control room evacuation and determined the issue was of very low safety significance (Green). This finding did not have a cross-cutting aspect since it was not indicative of present performance in that the performance deficiency occurred more than three years ago. |
| 05000458/FIN-2016007-03 | 2016Q2 | River Bend | Failure to Demonstrate that Appendix R Emergency Lights Satisfied their Maintenance Rule Performance Criteria | The team identified a finding for the failure to provide an adequate monitoring and testing program to demonstrate that the required Appendix R emergency lights satisfied the licensees maintenance rule performance criteria. Specifically, the failure to provide an adequate monitoring and testing program could result in a large number of Appendix R emergency lights failing to last the required 8 hours without being detected. The team determined that, because the licensee had changed their program to a biennial replacement frequency for the 8-hour batteries, reasonable assurance existed that the lights would function long enough for operators to perform the time critical manual actions directed by their fire protection program. The licensee entered this finding into their corrective action program as Condition Report CR-RBS-2016-03177. The failure to establish an adequate monitoring and testing program to demonstrate that the required Appendix R emergency lights would satisfy the licensees maintenance rule performance criteria was a performance deficiency. The performance deficiency was more than minor because if left uncorrected, the performance deficiency would have the potential to lead to a more significant safety concern. Specifically, the failure to provide an adequate monitoring and testing program could result in a large number of Appendix R emergency lights failing to function for the required 8 hours without being detected through licensee monitoring and testing. The team determined this finding affected the Mitigating Systems Cornerstone. The team evaluated this finding using Inspection Manual Chapter 0609, Appendix F, Fire Protection Significance Determination Process, dated February 28, 2005, because it affected the ability to reach and maintain safe shutdown conditions in case of a fire. The team assigned the finding to the post-fire safe shutdown category since it impacted the remote shutdown and control room abandonment element. The team assigned the finding a low degradation rating since the ability to reach and maintain safe shutdown conditions in the event of a control room fire would be minimally impacted by the potential failure of the emergency lights to function for 8-hours. Because this finding had a low degradation rating, it screened as having very low safety significance (Green) in Task 1.3.1. The finding did not have a cross-cutting aspect since it was not indicative of present performance in that the performance deficiency occurred more than three years ago. Specifically, the licensee began performing the 8-hour discharge test on a small sample of the batteries more than three years ago. |
| 05000458/FIN-2018003-01 | 2018Q3 | River Bend | Licensee-Identified Violation | This violation of very low safety significance 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.a of the NRC Enforcement Policy. Violation: Title 10 CFR Part 50, Appendix B, Criterion III, Design Control, requires, in part, that measures shall be established to assure that the design basis for those structures, systems, and components to which Appendix B applies is correctly translated into specifications, drawings, procedures, and instructions. The design basis for the control building air conditioning system, as specified in the updated safety analysis report, requires that the system be capable of performing its safety function in the event of a single failure in any component. Contrary to the above, the licensee failed to assure that the design basis was correctly translated into specifications for the control building air conditioning system. Specifically, while reviewing the control logic for the control building air conditioning system, the licensee discovered that the control logic was designed such that a single failure in a component in the control logic could have prevented the system from performing its specified safety function. |
| 05000482/FIN-2007003-01 | 2007Q2 | Wolf Creek | Circulating water roof loading exceeds design | On May 7, Wolf Creek received heavy rains and water leaks from the circulating water screen house roof were observed. On May 8, 2007, it was observed that the roof of the circulating water screen house had accumulated approximately eight inches of standing water and that the drains were blocked by debris. That same day, the drains were cleared and the roof was drained. It was not until inspector questioning that the design calculation for the roofs steel structure was reviewed for possible impacts; however, no roof damage was visually observed. The roof drains are described in Drawing A-121 and SPEC A-3862 with domed drain covers. The steel screens inside the drains became plugged with debris because outer dome covers over the screens were missing. On May 31, 2007, the dome drain covers were replaced. A work order was written in May 2001 because of standing water on the circulating water screen house roof caused by clogged drains due to missing dome covers. The debris was removed from the clogged drains in June 2001; however, the missing dome shaped drain covers were not replaced until after the May 7, 2007, occurrence. Based on the inspectors questioning of the May 2007 rains, Wolf Creek evaluated the impact of eight inches of water on the roof. The eight inches of water exceeded the design stress of approximately 16 ksi for the roofs most limiting I-beams. However, after reviewing the calculation, the loading did not exceed the yield stress for the A36 steel used in the most limiting I-beam of the roof. Directly below the most limiting I-beam is located all of the circulating water pump circuit breakers and the feeder circuit Breaker 4-26 for Bus SL-31. Bus SL-31 feeds the normal service water Pumps B and C and the electric fire water pump. Calculation A-3862-02 W01 describes the design stress for the load bearing steel structure of the circulating water screen house. Calculation A-3862-02 W01 provides for roof loading of snow, but not for standing water since the roof is designed with water drains. This calculation allows for a roof load of 20 pounds per square foot or approximately 3.8 feet of snow. The 3.8 feet of snow is approximately 3.8 inches of standing water. Thus, the added weight of eight inches of water was in excess of the loading specified in Calculation A-3862-02 W01. Based on the onsite meteorological tower, winds during the time the eight inches of standing water were on the roof ranged from 0 to 20 mph, however, this was determined not to be a significant contributor to roof stresses. On May 26, 2007, inspectors walked down the circulating water screen house roof to see the new dome covers and found them to be covered with insect debris. On May 26, 27, and 28 this issue re-occurred as Wolf Creek experienced heavy rains but only minor water depth was observed. Mechanics subsequently re-cleared the roof drains. This occurrence also called into question the ability of the dome covers to prevent roof gravel from migrating downstream to the drains because the gravel is smaller than the dome cover grating. This issue and the corrective actions are being tracked by Wolf Creek in Condition Reports 2007-001897 and -002599. Since additional inspection is needed to evaluate the facts and significance of all instances, this issue is being treated as an Unresolved Item (URI) 05000482/2007003-01, circulating water roof loading exceeds design. |
| 05000482/FIN-2007005-01 | 2007Q4 | Wolf Creek | EDG B Governor Failure Effect on Supplied Equipment | On December 20, 2007, Wolf Creek was performing the monthly test of EDG B. Prior to the operator placing his hand on the RAISE/LOWER handswitch, the load made a step increase from 4.2 MWE to 7.2 MWE and did not respond to lower signals from the control room handswitch. The EDG was tripped shortly thereafter. Troubleshooting examined the digital reference units (DRUs), the 2301A electronic engine governor, and the Woodward electromechanical governor mounted on the engine. Wolf Creek found the voltage readings on various terminals to be acceptable. However, resistance measurements across the two terminals that connect the electronic engine control unit and the electromechanical governor was expected to be 35 ohms and was found to have infinite resistance, indicating an open circuit. The cover plate of the governor was removed and one wire was found to be disconnected from its terminal. Wolf Creek has not determined the cause for this failure or its impact on safety systems. During interviews, Wolf Creek engineering stated that the electromechanical portion of the governor would fail and the EDG mechanical portion of the governor would drive the EDG to its high speed and maximum fuel setpoint. Because the EDG was synchronized to the grid, the inspectors judged it reasonable that the EDG would not cause the grid to increase in frequency but that the EDG would carry an amount of load equivalent to the mechanical governor setpoint. The inspectors questioned the licensee on the impact if this failure occurred during a valid safety injection signal or loss of offsite power. The inspectors found that such a frequency variation had not been previously analyzed. If the EDG governor failed in the observed manor, the EDG may have driven the bus and the connected safety equipment to a frequency that exceeds the TS 3.8.1 limit and/or the currently analyzed limit. This governor failure is being tracked by Wolf Creek in Condition Report (CR) 2008-000088. Since additional inspection is needed to evaluate the failure mode and significance of the failure, this issue is being treated as an Unresolved Item (URI) 05000482/2007005-01, EDG B governor failure effect on supplied equipment. |
| 05000482/FIN-2008002-01 | 2008Q1 | Wolf Creek | Failure to implement fire protection impairment control permit requirements and compensatory measures. | The inspectors identified a noncited violation of Technical Specification 5.4.1.d for failure to implement fire protection impairment control permit requirements and compensatory measures when operators received a trouble alarm on a fire detector in the auxiliary building. On January 26, 2008, operators discovered that Detector KC-104-XCH-ID-006 did not have a fire protection impairment control permit. This detector was adjacent to Detector KC- 104-XSH-ID-007 which was already inoperable in Impairment 2008-020. The licensees administrative procedure required fire detection in the area to be declared inoperable if two adjacent detectors are inoperable. This condition existed for approximately 24 hours and would have required a compensatory continuous fire watch for the period that both detectors were inoperable. The residents identified that the control room turnover checklist contains a section for listing the KC008 alarms; however, the two turnover checklists for the two shifts following the initial alarm did not identify Detector KC-104-XCH-ID-006 as a Detector KC-008 alarm. The failure to implement fire protection impairment control permit requirements and establish compensatory measures for the auxiliary building 2026-foot level was considered a performance deficiency. The finding was more than minor because it was associated with the Mitigating Systems Cornerstone attribute of protection against external factors and affected the cornerstone objective of ensuring the availability of systems that respond to initiating events to prevent undesirable consequences. Specifically, this issue relates to the protection against fire example of protection against external factors attribute because the detectors were inoperable without ensuring compensatory measures were in place. The finding was of very low safety significance because it involved compensatory measures for the fixed fire protection system and was assigned a low degradation rating since less than 10 percent of the fire detectors in the area were disabled. The finding has crosscutting aspects in the area of human performance associated with work practices because the licensee failed to apply appropriate human error techniques such as self and peer-checking techniques to avoid committing errors (H.4(a)) (Section 1R05) |
| 05000482/FIN-2008002-02 | 2008Q1 | Wolf Creek | Performing prohibited elective maintenance on offsite power during EDG maintenance. | A noncited violation of Technical Specification 3.8.1.B.4 was identified when the licensee performed elective maintenance in the switchyard and removed equipment from service that was prohibited by Technical Specifications while in an extended diesel generator outage. The inspectors determined that the failure to implement requirements of Technical Specification 3.8.1.B.4 was a performance deficiency. The finding was more than minor because it is associated with the equipment performance attribute for the mitigating systems cornerstone; and, it affected the cornerstone objective to ensure the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences (i.e. core damage). The finding was determined to be of very low safety significance because the issue resulted in the Train B offsite power being inoperable, but capable of supplying the safety bus for greater than 24 hours. Additionally, the cause of the finding has a human performance crosscutting aspect in the area associated with work control. Specifically, Wolf Creek did not ensure STS-IC-805B was appropriately coordinated within organizations to assure plant and human performance during the extended emergency diesel generator allowed outage time (H.3(b)) (Section 1R13) |
| 05000482/FIN-2008002-03 | 2008Q1 | Wolf Creek | Containment sump net positive suction head losses. | An unresolved item (URI) was identified when an operability determination dated January 22, 2008, was required to ensure that latent fabrication and calculation errors did not create unacceptable reductions in net positive suction head requirements for pumps in emergency core cooling systems. This new design information was associated with the already installed containment recirculation sump strainer modification. The associated vendor calculation, TD 6002 05, for clean strainer head loss omitted the head loss component associated with the orifices located in the strainer support plate. The size of the orifice beneath each strainer tube was not large enough to prevent head loss in excess of the net positive suction head required per the design conditions defined in the purchase specification supplied to the strainer vendor. The additional head loss due to the calculation correction was 2.28 feet. This resulted in required net positive suction head being less than available. Wolf Creek performed an operability determination review to demonstrate that the head loss margin could be recovered. The operability determination on January 22, 2008, addressed the smaller support plate orifice holes by using additional margin gained by separating the head loss of the RHR and containment spray piping systems to demonstrate lower losses and additional water inventory in containment prior to containment spray swapover to the sump. Wolf Creek is replacing the strainer support plate with larger orifices to regain head loss margin in Refueling Outage 16. However, additional concerns were provided to the licensee by the vendor on April 1, 2008, addressing nonconservative temperature correction through the orifices. Subsequent to this, the licensee will need to perform additional analyses to determine if negative margin existed during the last cycle and if the new orifice holes will provide positive margin. At the completion of the inspection period, there were still unresolved questions about the assumptions and results associated with the calculations used for regaining net positive suction head margin. These concerns require additional inspection and, when completed, the inspection results will require significance determination. This issue is considered unresolved pending additional NRC review of Wolf Creek operability determination calculations: URI 05000483/2008002-03, Containment Sump Net Positive Suction Head Losses |
| 05000482/FIN-2008002-04 | 2008Q1 | Wolf Creek | Failure to control area as a locked high radiation area. | The inspectors reviewed a self-revealing noncited violation of Technical Specification 5.7.2.a for failure to evaluate changing radiological conditions and control an area as a locked high radiation area. Specifically, on October 17, 2007, dose rates in Room 7604 increased to levels requiring posting as a Locked High Radiation Area, as a result of a vent and drain evolution. Dose rates reached a level of 1500 mRem/hour prior to the area being properly posted and controlled. This issue was entered into the licensees corrective action program as Condition Report 2007-003934. Immediate corrective actions included posting and controlling the area as a locked high radiation area. Other corrective actions included changing the vent and drain process to change the vent path. This finding is greater than minor because it is associated with the occupational radiation safety program and process attribute and affected the cornerstone objective, in that, the failure to properly post and control access to a locked high radiation area has the potential to increase personnel dose. This occurrence involves the potential for unplanned, unintended dose. Utilizing Inspection Manual Chapter 0609, Appendix C, Occupational Radiation Safety Significance Determination Process, the inspectors determined that the finding was of very low safety significance because it did not involve; (1) as low as is reasonably achievable planning and controls, (2) an overexposure, (3) a substantial potential for overexposure, or (4) an impaired ability to assess dose. This finding has a crosscutting aspect in the area of human performance associated with the work control component because licensee failed to appropriately plan work activities by incorporating job site conditions that may impact radiological safety (H.3(a)) (Section 2OS1(i)) |
| 05000482/FIN-2008002-05 | 2008Q1 | Wolf Creek | Failure to follow procedure | The inspectors reviewed a self-revealing noncited violation of Technical Specification 5.4.1 for failure to follow a licensee procedure. Specifically, on March 29, 2008, one of two radiographers conducting radiography operations in the quality control vault received a dose rate alarm on their electronic dosimeter. The two radiographers evaluated the dose received and decided to continue with radiography without notifying health physics personnel to evaluate the conditions. This issue was entered into the licensees corrective action program as Condition Report 2008-001181. Immediate corrective actions included restriction of the radiographers to log onto the radiation work permit and discussions with the radiographers and the contractors radiation safety officer. Long-term corrective action is still being evaluated. This finding is greater than minor because it is associated with the occupational radiation safety program and process attribute and affected the cornerstone objective, in that, the failure to stop work and notify health physics personnel for assistance had the potential to increase personnel dose. This occurrence involves the potential for unplanned, unintended dose. Utilizing Inspection Manual Chapter 0609, Appendix C, Occupational Radiation Safety Significance Determination Process, the inspector determined that the finding was of very low safety significance because it did not involve: (1) as low as is reasonably achievable planning and controls, (2) an overexposure, (3) a substantial potential for overexposure, or (4) an impaired ability to assess dose. This finding has a crosscutting aspect in the area of human performance associated with the decision making component because the radiographer and assistant failed to contact health physics personnel to discuss the circumstances surrounding the unexpected dose rate alarm (H.1(a)) (Section 2OS1(ii)) |
| 05000482/FIN-2008002-06 | 2008Q1 | Wolf Creek | Failure to establish reasonable expectation of operability. | The NRC identified a noncited violation of Technical Specification 5.4.1 for failure to follow the operability process on discovery of the centrifugal charging Pump A room cooler leak. On February 13, 2008, at 2:20 p.m., the control room was notified of a leak from the room cooler for the centrifugal charging pump. At that time, it could not be established if the leak would cause a loss of structural integrity of essential service water. Wolf Creek made no log entries at 2:20 p.m. stating its basis for immediate operability. At 3:50 p.m., Wolf Creek control room logs documented that centrifugal charging Pump A had a room cooler leak and structural integrity cannot be verified. Subsequent entry into Technical Specification 3.7.8 for the essential service water Pump A caused emergency diesel Generator A to be inoperable. Technical Specification 3.8.1, Condition I, states that with three alternating current sources inoperable (both emergency diesel generators and an offsite source), Technical Specification 3.0.3 shall be entered. Wolf Creek exited Technical Specification 3.0.3 at 4:13 p.m. when the inlet and outlet valves to centrifugal charging Pump As room cooler were closed. The inspectors could not locate any justification produced by Wolf Creek for the room coolers operability after 2:20 p.m. The inspectors determined that the failure to follow the operability process is a performance deficiency. The inspectors determined that this finding was more than minor because if left uncorrected, it could become a more serious problem if the operability process is not correctly applied. The finding screened to Phase 2 because the finding represents an actual loss of safety function of a single train of high head injection. A bounding risk of Green results from the Phase 2 presolved worksheets using an exposure time of less than 3 days for the Centrifugal Charging Pump (CCP) A (Fails to Run). The inspectors also determined that the finding had a human performance crosscutting aspect in the area associated with decision making because the licensee failed to use conservative assumptions in its operability decision and apply a requirement to demonstrate that the room cooler is operable in order to proceed rather than a requirement to demonstrate that it is inoperable (H.1(b)) (Section 4OA3.2(ii)) |
| 05000482/FIN-2008002-07 | 2008Q1 | Wolf Creek | Untimely corrective actions for CCP room cooler leads to NOED. | The inspectors identified a noncited violation of 10 CFR Part 50 Appendix B Criterion XVI, Corrective Action, because Wolf Creek failed to take timely corrective actions to prevent failure of the centrifugal charging pump A room cooler which resulted in a Notice of Enforcement Discretion (EA-08-052). The inspectors found that room Cooler SGL12A experienced leaks in October 1999, May 2003, October 2003, August 2004, October 2006, and again in February 2008. On March 14, 2007, Wolf Creek chose to delay SGL12As replacement until Refueling Outage 16 due to the required length of time to replace the cooler. On February 13, 2008, a circumferential flaw on an H-bend was discovered in SGL12A preventing it from performing its safety function. Inspectors reviewed corrective action Procedure AP 28A-100, Condition Reports, Revision 3 and found that a loss of a train to perform its safety function was considered a significant deficiency requiring corrective action to prevent recurrence. The inspectors reviewed this issue under Performance Improvement Requests 2005-2507 and 2004-0688, and Condition Report 2008-0467 and found that Wolf Creek designated prior failures nonsignificant. The failure to take timely corrective actions within 9 years was a performance deficiency. The inspectors determined that this finding was more than minor because it is associated with the equipment performance attribute for the mitigating systems cornerstone; and, it affected the cornerstone objective to ensure the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences (i.e. core damage). The finding screened to Phase 2 because the finding represents an actual loss of safety function of a single train of high head injection for greater than its Technical Specification 3.8.1.B.2 allowed outage time of 4 hours. Using an exposure time of less than 3 days for the scenario Centrifugal Charging Pump PBG05A (Fails to Run), a bounding risk of Green results from the Phase 2 presolved worksheets. Additionally, the cause of the finding has a human performance crosscutting aspect in the area associated with resources. Specifically, Wolf Creek did not ensure adequate resources to maintain long-term plant safety by minimizing the room coolers long-standing issues and preventive maintenance deferrals (H.2(a)) (Section 4OA3.2(iii)) |
| 05000482/FIN-2008002-08 | 2008Q1 | Wolf Creek | Transformer trip resulted in an unplanned eractor trip and forced outage. | On March 17, 2008, plant operators observed that steam generator water level was lowering and main feed pump speed was decreasing. Based on these indications, Wolf Creek operators manually tripped the plant. Posttrip immediate actions and followup actions were completed without deviation. An auto actuation of auxiliary feed water occurred due to low/low steam generator water levels as expected but no other ECCS or engineered safety feature actuations occurred. All plant equipment responded as expected. Following the trip, control room operators observed indications that the plant had experienced a loss of the XPB03 13.8 kV to 4.16 kV nonsafety transformer which powers PB003 4.16 kV nonsafety bus. Approximately 12 hours prior to the transformer trip, Wolf Creek had removed from service XPB04 transformer for planned maintenance and cross connected XPB04 transformer PB004 bus loads to the XPB03 transformer PB003 bus. This arrangement powered all three condensate pumps from the PB003 4.16 kV bus. The PB003 bus powers condensate Pumps A and C and the PB004 bus powers condensate Pump B. The XPB03 transformer trip resulted in losing power to all three condensate pumps which tripped the main feed pumps on low suction pressure. The licensees initial draft investigation of the cause of the transformer trip determined that two phases of the XPB03 transformer 4.16 kV output cables had overheated and failed. Additional investigation into the cable failures discovered that two multidirectional conductor connectors used to terminate two phases of the 1000 million circular mils (MCM) 4.16 kV bus cables were installed using the incorrect configuration. The cable connector had been installed using a 1500-2000 MCM configuration which resulted in the conductor connector bottoming out before applying sufficient compression to ensure adequate connection to the cable. Pending completion of the licensees root cause determination and consequence assessment by a Region IV Senior Reactor Analyst, additional inspection of the finding is needed to determine significance. This issue is considered unresolved pending additional NRC review of Wolf Creek root cause determination. This issue will be tracked as: Unresolved Item (URI) 05000483/2008002-08, Transformer Trip Resulted in an Unplanned Reactor Trip and Forced Outage |
| 05000482/FIN-2008002-09 | 2008Q1 | Wolf Creek | Failure to reestablish timely seal cooling for the reactor coolant pumps. | The inspectors identified a noncited violation of Technical Specification 5.4.1.d because Procedure OFN RP 017, \"Control Room Evacuation,\" Revision 21, failed to account for the needed actions to reestablish reactor coolant pump seal cooling. Failure to reestablish seal cooling in a timely manner could have resulted in a small break loss of coolant accident. This performance deficiency resulted from an inadequate postfire safe shutdown procedure. The inspectors determined the finding is greater than minor in that it affected the ability to achieve and maintain hot shutdown following a control room fire. This finding is associated with the mitigating systems cornerstone attribute of protection against external factors (e.g. fire). This finding affected the mitigating systems cornerstone objective to ensure the availability, reliability, and capability of systems that respond to external events (such as fire) to prevent undesirable consequences. In addition to the control room fire requiring operators to evacuate the control room, the fire would have had to affect components located in two physically separated panels. The licensee has Institute of Electrical and Electronics Engineers Standard 383 qualified cables and conductors throughout the plant. The Phase 3 risk evaluation performed by the NRC senior reactor analyst determined this deficiency had very low risk significance (Section 4OA3.5). |
| 05000482/FIN-2008002-10 | 2008Q1 | Wolf Creek | Failure to analyze motor-operated valve circuits. | The inspectors identified a noncited violation of License Condition 2.c(5) because the licensee failed to evaluate the impact of a motor-operated valve failure mechanism on their ability to implement postfire safe shutdown following a control room evacuation. The licensee determined that the failure mechanism affected 38 motor-operated valves and upon valve failure could affect their ability to implement their postfire safe shutdown procedure. A short circuit that bypassed the torque and/or limit switches could damage the valves and prevent repositioning of the valve in the postfire safe shutdown position. The inspectors determined this was a performance deficiency because the licensee failed to ensure that components necessary to safely shutdown the reactor would remain operable following a fire. This deficiency was more than minor, in that, it had the potential to impact the mitigating systems cornerstone objective to ensure the availability, reliability, and capability of systems that respond to external events (such as fire) to prevent undesirable consequences. In addition to the control room fire requiring operators to evacuate the control room, the fire would have had to affect components located in five different control panels. The Phase 3 risk evaluation performed by the NRC senior reactor analyst determined this deficiency had very low risk significance (Section 4OA5.2) |
| 05000482/FIN-2008002-11 | 2008Q1 | Wolf Creek | Licensee-Identified Violation | Licensee Technical Specification 5.7.1.b states in part that access to high radiation areas with dose rates not exceeding 1.0 Rem/hour at 30 centimeters from the radiation source shall be controlled by means of a radiation work permit that includes specification of radiation dose rates in the immediate work area and other appropriate radiation protection equipment and measures. Contrary to these regulations, on January 13, 2008, two quality control inspectors entered a pipe chase, a posted high radiation area, on the 1988 elevation of the auxiliary building using the wrong radiation work permit. The radiation work permit used by the licensee inspectors did not allow entry into a high radiation area. The violation was entered into the licensees corrective action program as CR 2008-00112. The finding was determined to be of very low safety significance because it did not involve: (1) ALARA planning and controls, (2) an overexposure, (3) a substantial potential for overexposure, or (4) an impaired ability to assess dose |
| 05000482/FIN-2008002-12 | 2008Q1 | Wolf Creek | Licensee-Identified Violation | Technical Specification 5.4.1.d specified that the licensee have fire protection procedures established, maintained, and implemented. Procedure OFN-RP-017, \"Control Room Evacuation,\" Revision 21, specified actions for a fire in the control room. Contrary to this requirement, the licensee determined that the procedure failed to provide mitigating actions for a failure of the field flash relay control circuit because of possible fire damage. As described in Section 4OA3.6, this finding was of very low safety significance |
| 05000482/FIN-2008002-13 | 2008Q1 | Wolf Creek | Licensee-Identified Violation | Title 10 of the Code of Federal Regulations, 10 CFR 50.48, requires all plants to meet Appendix R, Section III.G. Appendix R, Section III.G.2, specified that for equipment and cables of redundant trains of systems necessary to achieve and maintain hot shutdown located within the same fire area outside of primary containment shall be separated by one of the means specified or a diverse means implemented. Contrary to this requirement, the licensee did not provide the required separation and had not implemented a diverse means to ensure the required Class 1E air conditioning units would remain functional. This finding had a low degradation rating because of the very low likelihood of occurrence and the ability to achieve safe shutdown did not become directly affected; consequently, the deficiency had very low safety significance. The licensee included this item in their corrective action program (refer to Section 4OA3.8 |
| 05000482/FIN-2010006-05 | 2010Q3 | Wolf Creek | Failure to Perform Adequate Evaluation for Significant Conditions | The inspectors identified a cited violation 10 CFR Part 50, Appendix B, Criterion XVI, Corrective Action, because the licensee failed to perform an adequate evaluation to determine the cause of loss of offsite power induced water hammers and internal corrosion in the essential service water system and did not take corrective actions to preclude repetition of additional water hammer events and system leaks. Specifically, the licensee performed an apparent cause evaluation instead of a root cause evaluation as required, and the licensees evaluation did not consider metallurgical evaluations that were performed outside the corrective action program. The inspectors found that the licensee had not corrected a previous NCV 05000482/2009007-03, Failure to Correctly Screen ESW Piping Leaks for Significance, which resulted in the licensee failing to perform a root cause evaluation. Because the licensee failed to restore compliance within a reasonable time after NCV 05000482/2009007-03 was identified, this violation is being cited in a Notice of Violation in accordance with Section VI.A.1 of the NRCs Enforcement Policy. The licensees corrective action to this cited violation was to initiate Condition Reports 27212, 26466, and 27075, to evaluate and correct the identified conditions, to start a root cause evaluation and, separately, to evaluate the licensees failure to properly respond to NCV 05000482/2009007-03. The issue was more than minor because it is associated with the equipment performance attribute of the Mitigating Systems Cornerstone and affects the associated cornerstone objective to ensure the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences, and is therefore a finding. Using Inspection Manual Chapter 0609, the issue is determined to have very low safety significance because the finding is not a design or qualification issue confirmed not to result in a loss of operability or functionality; did not represent an actual loss of safety function of the system or train; did not result in the loss of one or more trains of nontechnical specification equipment; and did not screen as potentially risk significant due to a seismic, flooding, or severe weather initiating event. The inspectors determined that the cause of the finding has a crosscutting aspect in the area of problem identification and resolution associated with the component of corrective action program because the licensee failed to thoroughly evaluate problems such that the resolutions address causes and extent of conditions (P.1(c)) |
| 05000482/FIN-2011003-01 | 2011Q2 | Wolf Creek | No Procedure for Debris in Transformed and Tank Yards Prior to Severe Weather | The inspectors identified a noncited violation of Technical Specification 5.4.1.a, Administrative Procedures, for having no procedure to address onsite debris impacting plant equipment during severe weather. The inspectors walked down external areas of the plant on June 1 and June 9, 2011, prior to the onset of predicted severe thunderstorms and tornadoes. The inspectors found loose debris each time and brought it to the attention of the licensee who secured the materials. The inspectors walked down the transformer yard and tank yard during a thunderstorm on June 16 and found loose debris such as plywood, trash, wood planks, and fiberglass planks. The inspectors brought this to the attention of Wolf Creek and the materials were removed or secured. Wolf Creek initiated several condition reports but they only addressed immediate cleanup. Wolf Creek procedures had no steps for securing potential wind-driven projectiles prior to severe weather. After June 16, Wolf Creek wrote Condition Report 40573 which started a weekly maintenance activity to remove loose materials and added procedure steps to have operations walk down external areas prior to severe weather. This finding was more than minor because it impacted the protection against external factors attribute of the Initiating Events Cornerstone, and it affected the cornerstone objective to limit the likelihood of those events that upset plant stability and challenge critical safety functions during shutdown as well as power operations. The inspectors evaluated this finding using Inspection Manual Chapter 0609.04, and determined that it was of very low safety significance (Green) for June 16, 2011, because it did not contribute to both the likelihood of a reactor trip and the likelihood that mitigation equipment would be unavailable since the reactor was shutdown. Inspectors used Manual Chapter 0609 Appendix G, Checklist 4 for the other occurrences because Wolf Creek was in Modes 4 or 5. The finding again screened to Green because it did not increase the likelihood of a loss of inventory, did not cause the loss of reactor coolant system instrumentation, did not degrade the ability of the licensee to terminate a leak path or add inventory when needed, or degrade the ability to recover residual heat removal if it was lost. This finding has a cross-cutting aspect in the area of problem identification and resolution, specifically the corrective action program attribute because licensees short-term corrective actions failed to ensure debris was secured or removed prior to severe weather |
| 05000482/FIN-2011003-02 | 2011Q2 | Wolf Creek | Failure to Properly Establish Clearance Order Boundary Isolation Resulting in Loss of Component Cooling Water Inventory | The inspectors reviewed a self-revealing noncited violation of Technical Specification 5.4.1a, Administrative Procedures, for a loss of component cooling water train B inventory caused by inadequate clearance order verification. Valve HBV110 was stuck in position and was partially open. When the clearance order was implemented, the operators concluded the valve was already closed. Subsequently, the valve created a leakage path which exceeded the surge tank makeup flow capacity and required manual isolation by the control room operators to protect safety-related components. Wolf Creek has taken corrective actions to include communication of expected as-found equipment positions in pre-job briefings and the clearance order template. This issue is captured in the corrective action program as Condition Reports 34505 and 40219. Failure to properly establish clearance order boundary isolation was a performance deficiency. The performance deficiency is more than minor because it is associated with the equipment performance and human performance attributes of the Mitigating Systems Cornerstone and impacted the cornerstone objective of ensuring the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences. Using Inspection Manual Chapter 0609.04, the finding was determined to be of very low safety significance because the finding did not result in the loss of operability or functionality of the component cooling water train or screen as potentially risk significant due to a seismic, flooding, or severe weather initiating event or screen as potentially risk significant due to a seismic, flooding, or severe weather initiating event. The inspectors found that the finding had a cross-cutting aspect of work practices in the area of human performance associated with the communication of human error prevention techniques, such as holding pre-job briefings, self- and peer-checking, and proper documentation of activities |
| 05000482/FIN-2011003-03 | 2011Q2 | Wolf Creek | Failure to Assure Fillet Weld Met Size Requirements on Train B Charging Header Vent Line | The inspectors documented a self-revealing noncited violation of 10 CFR Part 50, Appendix B, Criterion IX, Control of Special Processes. Specifically, in October 2009, welders failed to ensure the fillet weld between the train B charging header and the half coupling used to attach two vent valves met the specified weld requirements. This weld failed in January 2011, rendering the train B charging system inoperable. The licensees extent of condition review identified 12 vent line welds which did not meet ASME code weld size requirements and/or procedural requirements for 2:1 weld taper configuration. Additionally, quality assurance inspectors failed to identify that the 2:1 taper weld requirements specified by procedure, and ASME minimum weld size requirements, were not met in multiple vent line welds. The weld was repaired and built up to the correct 2:1 aspect ratio. This issue was entered into the licensees corrective action program as Condition Reports 32648, 33686, 33689, and 36438. The finding was more than minor because it was associated with the equipment performance attribute of the Initiating Events Cornerstone and adversely affected the cornerstone objective to limit the likelihood of those events that upset plant stability and challenge critical safety functions during power operations. The inspectors performed a Phase 1 screening in accordance with Inspection Manual Chapter 0609.04, Phase 1 - Initial Screening and Characterization of Findings, and determined that the finding was of very low safety significance (Green) because the issue did not result in exceeding the technical specification limit for identified reactor coolant system leakage or affect other mitigating systems resulting in a total loss of their safety function. This finding had a cross-cutting aspect in the area of human performance, resources, because the licensee failed to ensure that personnel, specifically welders and quality assurance inspectors, were adequately trained in the procedural requirements and methods for measuring weld dimensions to assure nuclear safety. |
| 05000482/FIN-2011003-04 | 2011Q2 | Wolf Creek | Failure to Assure Separation of Stainless Steel and Carbon Steel Grinding and Cutting Equipment | The inspectors identified a noncited violation of 10 CFR Part 50 involving the failure of the licensee to ensure that weld preparation was protected from deleterious contamination in that drawers (located in the hot tool room) containing files, grinding wheels, flapper wheels, and cutting wheels, used for the purpose of weld preparation, contained a mixture of both stainless steel tools and carbon steel tools. The failure to separate tools used for stainless steel weld preparation from tools used for carbon steel preparation could result in the contamination of stainless steel welds by carbon steel and affect the material integrity and corrosion resistance. The licensee immediately removed the tools and replaced them with new tools stored separately for use on specific types of metal. This issue was entered into the licensees corrective action program as Condition Report 36444. The finding was more than minor because it was associated with the equipment performance attribute of the Initiating Events Cornerstone and adversely affected the cornerstone objective to limit the likelihood of those events that upset plant stability and challenge critical safety functions during power operations, and if left uncorrected the finding would become a more significant safety concern. The inspectors performed a Phase 1 screening in accordance with Inspection Manual Chapter 0609.04, Phase 1 Initial Screening and Characterization of Findings, and determined that the finding was of very low safety significance (Green) because the issue did not result in exceeding the technical specification limit for identified reactor coolant system leakage or affect other mitigating systems resulting in a total loss of their safety function. This finding had a cross-cutting aspect in the area of human performance, resources, because the licensee did not provide complete, accurate, and up-to-date procedures for the preparation of stainless steel and carbon steel welds. |
| 05000482/FIN-2011003-05 | 2011Q2 | Wolf Creek | Failure to Assure Configuration Control of Safety-Related Systems | The inspectors identified a noncited violation of 10 CFR Part 50, Appendix B, Criterion III, Design Control, involving the failure of the licensee to review the suitability of installing brass fittings and leaving test fittings on pressure, differential pressure, and flow transmitter equalizing block valve drain ports instead of the design specified stainless steel manifold plugs. During a boric acid walkdown, the inspectors identified that drain ports on the equalizing block of two separate reactor coolant system flow transmitters had brass fittings installed instead of the design specified stainless steel fittings. In response to inspector concerns about the brass fittings, the licensee subsequently discovered that a design configuration nonconformance existed by leaving the test fittings on the drain port during plant operation. Licensee Drawing J-17D22 specifies that manifold plugs be installed in the drain ports during plant operation. The licensee immediately replaced the brass caps with stainless steel fittings. This issue was entered into the licensees corrective action program as Condition Report 36439. The finding was more than minor because it was associated with the design control attribute of the Initiating Events Cornerstone and adversely affected the cornerstone objective to limit the likelihood of those events that upset plant stability and challenge critical safety functions during power operations. The inspectors performed a Phase 1 screening in accordance with Inspection Manual 0609.04, Phase 1 Initial Screening and Characterization of Findings, and determined that the finding was of very low safety significance (Green) because the issue would not result in exceeding the technical specification limit for identified reactor coolant system leakage or affect other mitigating systems resulting in a total loss of their safety function. The inspectors also determined that the finding had a cross-cutting aspect in the area of human performance, resources, because the licensee did not provide adequate training of personnel so that the inappropriately installed fittings could be identified during system walkdowns. |
| 05000482/FIN-2011003-06 | 2011Q2 | Wolf Creek | Inadequate Acceptance Criteria for Postmaintenance Testing of the Startup Feedwater Pump | The inspectors identified a finding involving the failure to follow the requirements of Procedure AP 16E-002, Post Maintenance Testing Development, for the startup feedwater pump. On November 4-6, 2010, Wolf Creek workers disassembled the startup feedwater pump for numerous preventive and corrective activities including removing the rotating element. On November 17, 2010, Wolf Creek conducted surveillance Procedure STN AE-007, Startup Main Feedwater Pump Operational Test, following reassembly. The only acceptance criteria listed in this procedure is that the motor-driven feedwater pump starts from the control room with no local operator action. The inspectors found this contrary to Procedure AP 16E-002, which requires acceptance criteria for a pump flow capacity test, vibration, bearing and lubrication temperatures, motor current, external leakage, and lubrication level be found satisfactory. This issue is captured in the corrective action program as Condition Report 39494. Wolf Creek issued a new work package to conduct a single-point pump capacity test and complete the required postmaintenance testing. Wolf Creek found, pending final review, that initial calculations show that the pump design is capable of enough flow to provide a heat sink in emergency operating procedures. Failure to follow Procedure AP 16E-002 for developing test criteria for plant equipment after the completion of maintenance activities is a performance deficiency. The finding is more than minor because it is associated with the Mitigating Systems Cornerstone attribute of equipment performance and it adversely affects the cornerstone objective of ensuring the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences. Using Inspection Manual Chapter 0609.04, the inspectors determined that the finding had very low safety significance (Green) because it did not result in a loss of system safety function, an actual loss of safety function of a single train for greater than its technical specification allowed outage time, or screen as potentially risk significant due to a seismic, flooding, or severe weather initiating event. The inspectors determined that the finding had a cross-cutting aspect in the area of problem identification and resolution. Specifically, Wolf Creek created a testing procedure in response to a root cause evaluation, but did not consider acceptance criteria to ensure that the pump performs acceptably. |
| 05000482/FIN-2011003-07 | 2011Q2 | Wolf Creek | Failure to Correct Procedure for Opening Main Steam Isolation Valves | The inspectors identified a cited violation of Technical Specification 5.4.1.a, Administrative Procedures, involving Wolf Creeks failure to correct Procedure SYS AB-120 for main steam isolation valve operation. Specifically, between March 3, 2010, and March 19, 2011, Wolf Creek experienced repeat cases of safety-system actuations due to Procedure SYS AB-120 containing inadequate steps to establish conditions necessary to open a main steam isolation valve. Corrective actions were previously limited to steam header pressures below 300 psi. Wolf Creek commenced a root cause evaluation of the March 19, 2011, safety injection under Condition Report 34964. Due to Wolf Creeks failure to restore compliance from previous NCV 05000482/2010004-01 within a reasonable time after the violation was identified, this violation is being cited as a Notice of Violation consistent with the Enforcement Policy. Failure to correct deficiencies in Procedure SYS AB-120 for steam pressures above 300 psi was a performance deficiency. The inspectors determined that this finding was more than minor because it impacted the equipment performance attribute for the Initiating Events Cornerstone, and it affected the cornerstone objective to limit the likelihood of those events that upset plant stability and challenge critical safety functions during shutdown as well as power operations. Specifically, this issue relates to the configuration control attribute for shut down equipment alignment. The inspectors evaluated the significance of this finding using Inspection Manual Chapter 0609.04. Assuming worst case degradation, the finding resulted in exceeding the technical specification limit for reactor coolant system leakage due to the pressurizer power-operated relief valve cycling. Therefore, the inspectors screened the finding to a Phase 2 review by the senior reactor analyst. The senior reactor analyst used the Wolf Creek SPAR model and concluded that the incremental core damage probability was 3.7E-7 (Green). The inspectors found that the cause of the finding has a cross-cutting aspect in the area of problem identification and resolution associated with the corrective action program. Specifically, several evaluations failed to have an adequate extent of condition review and did not find that procedures were inadequate for opening a main steam isolation valve above 300 psi |