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	Quarter	Site	Title	Description
05000413/FIN-2018010-02	2018Q3	Catawba	Operability of the VZ and RN Systems were not Assured	The team identified a Green non-cited violation of 10 CFR Part 50, Appendix B, Criterion III, Design Control for the failure to assure that applicable regulatory requirements for the safety-related service water pump house environmental controls were correctly translated into specifications, drawings, procedures, and instructions. Specifically, the licensee failed to translate the IEEE 279-1971 design basis and requirements for the environmental controls.
05000413/FIN-2018010-01	2018Q3	Catawba	Inadequate Engineering Analyses to Support Design Basis Requirements	The team identified four examples of a Green non-cited violation of title 10 Code of Federal Regulations Part 50, Appendix B, Criterion III, Design Control. Specifically, Catawba failed to verify the electrical design of safety-related switch gear for the emergency core cooling system equipment and distribution systems (4160 volts-alternating-current (VAC), 600 VAC, and 125 volt-direct- current (VDC)): 1) Some circuit breakers had inadequate voltages that did not meet the minimum qualified requirements (90 VDC), 2) The design was not evaluated for the effects of electrical transients on control voltages that could affect the assumptions in the plant safety analyses for sequencing of loads and potentially affect the control fuses, 3) The effects of degraded voltages was not correlated to the component protection devices to prevent damage or unavailability of equipment during an event, and 4) Motor control centers and components located in the diesel control area were not qualified to perform their safety function during expected environmental transients.
05000259/FIN-2018010-01	2018Q2	Browns Ferry	Licensee-Identified Violation	The Browns Ferry Nuclear Plant, Unit 3, Renewed Facility Operating License, DPR-68, License condition 2.C(7) required, in part, that TVA Browns Ferry Nuclear Plant shall implement and maintain in effect all provisions of the approved fire protection program that comply with 10 CFR 50.48(a) and 10 CFR 50.48(c)... Specifically, 10 CFR 50.48(c)incorporated by reference National Fire Protection Association Standard 805 (NFPA 805), and NFPA 805 section 2.4.2.2.2, Other Required Circuits, required in part, Other circuits that share common power supply and/or common enclosure with circuits required to achieve nuclear safety performance criteria shall be evaluated for their impact on the ability to achieve nuclear safety performance criteria. (a) Common Power Supply Circuits. Those circuits whose fire induced failure could cause the loss of a power supply required to achieve the nuclear safety performance criteria shall be identified. This situation could occur if the upstream protection device (i.e., breaker or fuse) is not properly coordinated with the downstream protection device. Contrary to the above, since June 22, 2016, when the NFPA 805 requirements went into effect, the licensee did not implement and maintain in effect all provisions of the approved fire protection program, because the licensee did not correctly evaluate circuits that share common power supply for their impact on their ability to achieve nuclear safety performance criteria in accordance with NFPA 805.Significance: The team evaluated the finding in accordance with NRC Inspection Manual Chapter (IMC) 0609, Attachment 4, Initial Characterization of Findings, issued October 7, 2016, for Mitigating Systems, and IMC 0609, Appendix F, Fire Protection Significance Determination Process, issued May 2, 2018, and determined the finding to be of very low
05000324/FIN-2018011-03	2018Q2	Brunswick	Potential Unjustified Activation Energy for Rosemont Transmitters	The licensee used 0.78 eV as the limiting activation energy for Rosemount transmitters. The activation energy was based upon an academic paper documenting experimental work performed for the early space program and first published in 1965. The paper cautioned the reader that the methods used were experimental and were not validated. A 0.5 eV activation energy for electronics was documented by the Electric Power Research Institute (EPRI) report NP-1558, which attributed it to electron migration of aluminum. Reports published by the Institute of Electrical and Electronics Engineers (IEEE) indicated that activation energies for various electronics and their failure modes could range from 0.5-0.66 eV. The licensee did not document an independent failure modes and effects analysis to justify the activation energy that they used. In addition, the licensee chose to use less limiting activation energies that were not proven to be justified. Finally, the licensee was unable to demonstrate acceptable margins for extrapolation confidence. The IEEE standard 323-1974, section 6.5.2, Mathematical Modeling, stated, the first step in the qualification by analysis is generally the construction of a valid mathematical model of the electric equipment to be qualified. The mathematical model shall be based upon established principles, verifiable test data, or operating experience data. The mathematical model shall be such that the performance of the electric equipment is a function of time and the pertinent environmental parameters. All environmental parameters listed in the equipment specification must be accounted for in the construction of the mathematical model unless it can be shown that the effects of the parameter of interest are dependent on the effects of the remaining environmental parameters. Planned Closure Actions: The team must determine whether the activation energy used for the transmitters was appropriate and, if not, whether the licensee had the responsibility to verify the information provided by their vendors and contractors. The region is discussing this issue with NRC headquarters to find a resolution to this issue.
05000324/FIN-2018011-02	2018Q2	Brunswick	Failure to Evaluate Effects of MOV Space Heaters on Qualified Life	The NRC identified a Green finding and associated non-cited violation of 10 CFR 50.49(e)(5) for the licensees failure to evaluate the effects of additional heat rise on the qualified life of Limitorque controls.
05000324/FIN-2018011-01	2018Q2	Brunswick	Failure to Justify Qualified Life Extension of ASCO Solenoid Operated Valves	The NRC identified a Green finding and associated non-cited violation of 10 CFR 50.49(e)(5) for the licensees failure to justify life extensions of ASCO solenoid operated valves (SOVs
05000369/FIN-2018010-01	2018Q1	Mcguire McGuire	Failure to Update Offsite Circuit Operability Limit for Single Busline Alignment	The inspectors identified a Green finding for the licensees failure to update calculations as required by procedure AD-EG-ALL-1117, Design Analyses and Calculations, Rev. 5. Specifically, the licensee revised calculation MCC-1381.05-00-0258, U1, 6.9kV, 4.16kV & 600V Auxiliary Power Systems Safety-Related Voltage Analysis, Rev. 6, to identify the effect of longer motor-driven auxiliary feedwater pump (CA pump) acceleration times on the switchyard voltage limits in place to ensure offsite power source operability. However, the licensee failed to update the previously analyzed condition of only one offsite circuit in service from the switchyard to the 4160V Class 1E buses via the unit step-up and unit auxiliary transformers (single busline alignment). As a result, there was no verification that the offsite circuit operability limit was adequate during single busline alignment
05000395/FIN-2018010-01	2018Q1	Summer	Failure to Justify Activation Energy for Valcor SOV XVX06050A	The qualification of the Valcor SOVs, completed in 1979, used the 10oC rule to determine the accelerated aging rate, which was equivalent to a 0.831 eV activation energy derived for Valcors ethylene propylene rubber (EPR). The inspectors determined that 0.831 eV for EPR, although realistic, it was not the most limiting identified for EPR. Valcor originally qualified the SOVs for 40 years at 120oF, however many of the valves are normally energized and will see temperatures exceeding 120oF. The SOV, XVX06050A, is a normally energized open valve that de-energizes to close on a containment isolation phase A signal and opened post-accident for hydrogen analyzing in the reactor building. In 1988, Impell Corporation, the licensees contractor, reanalyzed the qualification and determined that DuPont Tefzel insulation was the most limiting component instead of EPR and that a 50% loss of tensile strength was the limiting failure mechanism at 0.95 eV activation energy. To extrapolate a new activation energy, Impell estimated data points from a rudimentary log life plot that did not have any actual test data points. Impell obtained the plots from a DuPont Tefzel design handbook which also contained the log life plot for the elongation to break failure parameter of Tefzel, which appeared more limiting than tensile strength. Because the new activation energy extrapolation did not use actual test data, the extrapolation of that data was less limiting than the original qualification activation energy, and the elongation to break failure parameter was not evaluated, the team determined the new activation energy was not justified. FSAR Section 3.11.2.1.3 stated that the environmental qualification of Class 1E equipment is in conformance with RG 1.89, Rev. 1. Section C.5.c of the RG stated that the aging acceleration rate and activation energies used during qualification testing and the basis upon which the rate and activation energy were established should be defined, justified, and documented. The licensee did not find the original qualification activation energy to be in error or non-conservative. The licensee chose to develop an activation energy from less limiting log life plots, which was non-conservative. In addition, without actual data for the log life plots, the licensee was unable to demonstrate acceptable margins for uncertainty. The team determined that the valve would have exceeded its qualification based on the original qualification and unjustified use of the new activation energy. Corrective Actions: On February 19, 2018, the licensee entered this issue into their corrective action program as CR 18-00754 and performed an immediate determination of operability to verify that the valve could still perform its intended safety function. Corrective Action Reference: CR 18-00754 6 EnclosurePerformance Assessment: The failure to justify the basis upon which the activation energy of Valcor SOV XVX06050A was established in accordance with RG 1.89 Section C.5.c was a performance deficiency (PD). The PD was determined to be more than minor because it adversely affected the SSC and Barrier Performance attribute of the Barrier Integrity cornerstone and adversely affected the cornerstone objective of providing reasonable assurance that physical design barriers protect the public from radionuclide releases caused by accidents or events. Specifically, the failure to justify the activation energy used for Tefzel adversely affected the reliability of the solenoid to maintain its qualification over the entire 40 year qualified life of the plant. The team used inspection manual chapter (IMC) 0609, Att. 4, Initial Characterization of Findings, issued December 7, 2016, for barriers, and IMC 0609, App. A, The Significance Determination Process (SDP) for Findings At-Power, issued June 19, 2012, and determined the finding to be of very low safety significance (Green) because the finding did not represent an actual open pathway in the physical integrity of reactor containment, containment isolation system, and heat removal components and did not involve an actual reduction in function of hydrogen igniters in the reactor containment. Since the underlying cause of the issue occurred in 1988, the team determined that no crosscutting aspect was applicable because the finding was not indicative of current licensee performance. Enforcement: Title 10 CFR 50.49 (e)(5) states Equipment qualified by test must be preconditioned by natural or artificial (accelerated) aging to its end-of-installed life condition. Consideration must be given to all significant types of degradation which can have an effect on the functional capability of the equipment. If preconditioning to an end-of-installed life condition is not practicable, the equipment may be preconditioned to a shorter designated life. The equipment must be replaced or refurbished at the end of this designated life unless ongoing qualification demonstrates that the item has additional life. Contrary to the above, since August 30, 1988, the licensee failed to age Valcor SOV XVX06050A to its end of life condition and to replace the equipment at the end of its designated life. This violation is being treated as an NCV, consistent Section 2.3.2 of the Enforcement Policy.
05000395/FIN-2018010-02	2018Q1	Summer	Failure to Verify the Seismic Qualification of Valcor Solenoid Operated Valve XVX06050A	Calculation VCS-0423-DC-1, Valcor Voltage and Current Reducing Resistors, Rev. 0, dated September 10, 1981, located in Tab E1 of EQDP-H-VO4-V01 for solenoid operated valve XVX06050A, indicated a 300 ohm resistor was in series with the valve and that it reduced the voltage in the coil to approximately 32VDC at minimum conditions. The team questioned if the valve was seismically qualified at the lower voltage since the seismic qualification in test report QR 52600-515, Section 4.2.5, Seismic Vibrations, stated that it was performed at 108VAC. The team noted that the Valcor SOV was not installed in the same configuration that it was seismically qualified. The failure to ensure the valve was seismically qualified, as configured, did not ensure that damage would not occur during a seismic event. FSAR Section 3.10 stated that seismic qualification must be done in 7 Enclosureaccordance with IEEE 344-1971. Section 3.2.2.2 of IEEE 344-1971 states the device being tested should demonstrate its ability to perform its intended safety function and sufficient monitoring equipment should be used to evaluate its performance. The team determined that the licensee did not demonstrate the seismic qualification of valve XVX06050A in its current plant configuration at reduced voltage. Corrective Actions: On February 15, 2018, the licensee entered this issue into their corrective action program as CR 18-00686 and performed an immediate determination of operability to verify that the valve could still perform its intended safety function. Corrective Action Reference: CR 18-00686 Performance Assessment: The licensees failure to verify the adequacy of the seismic design and qualification of valve XVX06050A in accordance with IEEE 344-1971 was a performance deficiency (PD). The PD was determined to be more than minor because it adversely affected the Design Control attribute of the Barrier Integrity cornerstone and adversely affected the cornerstone objective of providing reasonable assurance that physical design barriers protect the public from radionuclide releases caused by accidents or events. Specifically, the failure to verify the adequacy of design for seismic qualification of the valve resulted in the valve being installed in an unqualified configuration. The team used inspection manual chapter (IMC) 0609, Att. 4, Initial Characterization of Findings, issued December 7, 2016, for barriers, and IMC 0609, App. A, The Significance Determination Process (SDP) for Findings At-Power, issued June 19, 2012, and determined the finding to be of very low safety significance (Green) because the finding did not represent an actual open pathway in the physical integrity of reactor containment, containment isolation system, and heat removal components and did not involve an actual reduction in function of hydrogen igniters in the reactor containment. Since the underlying cause of the issue occurred on August 30, 1988, the team determined that no crosscutting aspect was applicable because the finding was not indicative of current licensee performance. Enforcement: Title10 CFR Part 50, Appendix B, Criterion III Design Control, requires, in part, that The design control measures shall provide for verifying or checking the adequacy of design, such as by the performance of design reviews, by the use of alternate or simplified calculational methods, or by the performance of a suitable testing program. Contrary to the above, since August 30, 1988, the licensee failed to verify valve XVX06050A was seismically qualified in its current configuration in accordance with IEEE 344-1971. This violation is being treated as an NCV, consistent Section 2.3.2 of the Enforcement Policy.
05000395/FIN-2018010-03	2018Q1	Summer	Inadequate Radiation Harsh Environmental Qualification of Reactor Building Spray Pump A	During the review of EQDP-H-MO1-G03 for RB spray Pump A, the team noted that the pump was qualified for a maximum harsh environment of 1x106 radiation absorbed dose (rad); however, the total integrated dose (TID) was expected to be greater than 6.1x106rad TID over its 40 year life. Tab F1 of the EQDP, containing the equipment qualification report of the motors dated June 1977, stated that the maximum integrated radiation dose justified by the report over the 40 year operating life of the motor was 1x106 rads. The EQDP stated that component data shows that all components are suitable for the rated 1x106 rads integrated dose with the exception of (a) unfilled polyester resin and (b) the Dacron felt. In all cases, the polyester resins are filled to various degrees with glass or similar products. Such filling of the resin results in a significant increase in the radiation resistance of the combination -- as high as 9x108 rads. The Dacron felt by itself, at a threshold resistance of 8.6x105 rads, approaches the required radiation resistance but the felt is designed to be saturated with the impregnating epoxy resin and occurs only in this state. No specific data is available on the radiation resistance of the combination (Dacron filled epoxy), but the evidence indicates that the combination will exceed the required 1x106 rads. The team noted that the expected TID dose over the 40 year life of the RB spray pump A motor exceeded the original qualification provided in this test report. In order to ensure the pump was qualified for its radiation environment, the licensee had Impell Corporation perform Calculation 0980-036-030, Qualified Radiation Levels for GE Motors, Rev. 0, in August 31, 1988, which concluded that the motor was qualified for 1.5x107rads. The re-analysis was not based on partial type testing of the motor or a similar motor in accordance with NUREG-0588, but only reinterpreted the same material information previously provided by GE. The team noted that the reanalysis made different assumptions than GE did on the material characteristics of an unknown polyester resin fill material and Dacron felt. For the polyester resin, Impell could not determine what the fill material was or how much fill was used, but determined that it had a higher radiation resistance. For the Dacron felt, Impell assumed that the Dacron would not be a weak link in radiation resistance because of the epoxy. These assumptions were used to justify increasing the radiation qualification of the RB spray pump motor. The team determined that the original qualification of 1x106 rads was appropriate and was not proven to be inadequate by Impell because of the uncertainties documented by GE, and the lack of actual type testing information for the motor to support the Impell assumptions. FSAR Section 3.11.2 states that the licensee is committed to NUREG 588 Category II requirements. Section 2.1.2 of NUREG 588 states The choice of the methods selected is largely a matter of technical judgment and availability of information that supports the conclusions reached. Experience has shown that qualification of equipment subjected to an accident environment without test data is not adequate to demonstrate functional operability. In general, the staff will not accept analysis in lieu of test data unless (a) testing of the component is impractical due to size limitations, and (b) partial type test data is provided to support the analytical assumptions and conclusions reached. Section 2.1(3)(a) of NUREG 588 states Equipment that must function in order to mitigate any accident should be qualified by test to demonstrate its operability for the time required in the environmental conditions resulting from that accident. The team determined that the basis for raising the radiation qualification was not justified and that the qualification test report did not demonstrate that RB spray pump A was qualified over its 40 year operating life. Corrective Actions: On February 16, 2018, the licensee entered this issue into their corrective action program as CR 18-00707 and performed an immediate determination of operability to verify that the pump could still perform its intended safety function. 9 EnclosureCorrective Action Reference: CR 18-00707 Performance Assessment: The licensees failure to justify that RB spray pump A could perform its function under the radiation conditions expected during an accident in accordance with Section 2.1(3)(a) of NUREG 588 was a PD. The PD was determined to be more than minor because it adversely affected the Equipment Performance 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. Specifically, the failure to qualify the pump to expected radiation conditions adversely affects the pumps capability to perform its intended safety function during a design basis accident. The team used inspection manual chapter (IMC) 0609, Att. 4, Initial Characterization of Findings, issued December 7, 2016, for mitigating systems, and IMC 0609, App. A, The Significance Determination Process (SDP) for Findings At-Power, issued June 19, 2012, and determined the finding to be of very low safety significance (Green) because the finding was a deficiency affecting the qualification of a mitigating structure, system, and component (SSC), and the SSC maintained its operability. Since the underlying cause of the issue occurred on August 31, 1988, the team determined that no crosscutting aspect was applicable because the finding was not indicative of current licensee performance. Enforcement: Title 10 CFR 50.49 (e)(4) requires, in part, that the electric equipment qualification program must include and be based on radiation, and the radiation environment must be based on the type of radiation, the total dose expected during normal operation over the installed life of the equipment, and the radiation environment associated with the most severe design basis accident during or following which the equipment is required to remain functional, including the radiation resulting from recirculating fluids for equipment located near the recirculating lines and including dose-rate effects. Contrary to the above, since August 31, 1988, the licensee failed to qualify RB spray pump A to the total dose expected during normal operation over the installed life of the pump and during the most severe DBA. This violation is being treated as an NCV, consistent Section 2.3.2 of the Enforcement Policy
05000395/FIN-2018010-04	2018Q1	Summer	Unjustified Qualified Life for ASCO Valves	The NRC opened a Unresolved Item (URI) to determine if a performance deficiency was more than minor. In 1993, the licensees contractor, Impell Corporation, re-analyzed the qualified life established by ASCO qualification report AQR-67368 and a field notification from ASCO dated 10/27/1989. Impell erroneously used the heat rise temperatures from the field notification for both the AQR-67368 test samples accelerated aging temperature and the actual service temperatures in various plant locations. Replacing the actual test specimens documented accelerated aging temperature with an assumed temperature was not justified. As a result, when using the actual temperature identified in the qualification report, many of these solenoids are currently beyond their qualified lives. The licensee provided an alternate heat rise test report less limiting than the ASCO testing to justify that the ASCO valves were within their service lives, report 8058-001-2000-RA-0001-R00, Environmental Qualification Temperature Test of ASCO 206 and NP Series Solenoid Valves, dated June 2000. The teams evaluation must determine whether the alternate report is applicable to the licensee, and, if so, whether the test report indicated that the ASCO testing was invalid to conclude that the valves are currently within their qualified lives. 10 EnclosureNUREG-0588 Section 4(6) and Regulatory Guide 1.89, Rev. 1, Regulatory Position 5.c, required, in part, that the aging acceleration rate and the basis upon which it was established be described, documented, and justified. The team determined that the failure to justify the aging acceleration rate was a performance deficiency. However, a review of the additional information is warranted to determine if the performance deficiency is more than minor. The licensee entered the performance deficiency into their corrective action program as CR-18-00175 and determined that preliminary calculations indicated that the ASCO valves are currently operable based on the additional information provided for review.
05000395/FIN-2018010-05	2018Q1	Summer	Potential High Radiation Dose Areas with Unqualified Components	The NRC opened a URI to determine if a performance deficiency exists. The licensee did not perform analysis to determine the radiation exposure to shielded components adjacent to electrical and blank penetrations on the outboard side through containment. As a result, many mild environment components may be adversely affected. The inboard side of the penetrations is exposed to rad levels approaching 9X107 rads and the out board side is shielded by thin steel plates with electrical pass-thru holes. The inspectors noted that there were many areas of the plant identified as mild environments with unanalyzed penetrations. For example, the inspectors observed that the two trains for the plant service water were adjacent to unanalyzed penetrations. The components adjacent to the outboard side of the penetrations may be unqualified for service conditions expected during the most severe DBA as required by 10 CFR 50.49(e)(4). NUREG-0588 Section 1.4 "Radiation Conditions Inside and Outside Containment," required, in part, that "(8) Shielded components need be qualified only to the gamma radiation levels required..." and that "(12) Equipment that may be exposed to radiation doses below 104 rads should not be considered to be exempt from radiation qualification, unless analysis supported by test data is provided to verify that these levels will not degrade the operability of the equipment below acceptable values. The licensee provided a white paper for this issue that asserts that consideration of radiation streaming was not part of their licensing basis, thus enforcement would be addressed through a backfit analysis in accordance with 10 CFR 50.109. The team must determine whether the site licensing basis required consideration of radiation streaming and whether a backfit analysis would be appropriate in lieu of enforcement. The licensee captured this issue in their corrective action program as CR-18-00684 and determined that the process for qualification of equipment used was found acceptable per the VCS SER. Further evaluation will be performed under this CR but currently all components are qualified to their expected operating conditions and will perform their design functions. At worst, the EQ life of components may be reduced. All equipment in penetration areas are operable.
05000395/FIN-2018010-06	2018Q1	Summer	Potential Unjustified Activation Energy for Barton Transmitters	The contractor, Impell Corporation, changed the activation energy for the Barton transmitters from 0.5 eV to 0.78 eV. The 0.78 eV was based upon an academic paper documenting experimental work, apparently, performed for the early space program and apparently first published in 1965. The paper cautioned the reader that the methods used were experimental and were not validated. A 0.5 eV activation energy for electronics was documented by the Electric Power Research Institute (EPRI) report NP-1558, which attributed it to electron migration of aluminum. The report was available to the licensee at the time of the change. Reports published by the Institute of Electrical and Electronics Engineers (IEEE) indicated that activation energies for various electronic failure modes could range from 0.5-0.66. Impell did not document an independent failure modes and effects analysis to justify the activation energy that they used. The licensee did not find the original qualification activation energies to be in error or non-conservative. The licensee chose to use less limiting activation energies that may not have been proven to be justified. In addition, the licensee was unable to demonstrate acceptable margins for extrapolation uncertainty. FSAR Section 3.11.2.1.3 stated that the environmental qualification of Class 1E equipment is in conformance with RG 1.89, Rev. 1. The RG in Section C.5.c stated that the aging acceleration rate and activation energies used during qualification testing and the basis upon which the rate and activation energy were established should be defined, justified, and documented. NUREG 0588 Section 5(2), Qualification Documentation, specified, in part that a certificate of conformance by itself is not acceptable unless it is accompanied by test data and information on the qualification program. The licensee captured this issue in their corrective action program as CR-18-00500, and determined that the NRC challenged the qualified life for Barton installed as IPT00456 based on an activation energy. VC Summer engineering does not agree with the NRC, nor do the OEMs Barton, Weed/Foxboro and Rosemount who have reviewed their prior research and state that it is suitable and adequate for our applications. The team must determine whether the activation energy used for the Barton transmitters was appropriate and, if not, whether the licensee had the responsibility to verify the information provided by their vendors and contractors.
05000390/FIN-2018010-01	2018Q1	Watts Bar	Potential Failure to Request NRC Approval to Increase the OPT and OTT Response Times	The reactor trips that protect from fuel damage that could result from departure from nucleate boiling around the fuel are identified as over-temperature-change-in-temperature (OTT) and over-power-change-in-temperature (OPT). The trips use the temperature from the reactor coolant systems hot legs as inputs into complex equations. In 1991, the licensee requested a license amendment to upgrade the Temperature Averaging System (TAS) and protection system to digital technology (Eagle 21 protection system). The Westinghouse topical reports (TR) for the TAS and Eagle 21 was reviewed and the TAS was approved with conditions for the RTD response times, electronic delay times, and surveillance test uncertainties in NUREG 847, the Safety Evaluation Report (SER), Supplement 8 dated January 1992. The SER specified, that the overall response time (RTD response time plus electronics delay) for the new RdF RTDs is 0.5 second longer (6.5 vs. 6.0 seconds) than the former Rosemount RTDs. This leaves a margin of 0.5 second (7.0-6.5) between the analysis and overall RTD response time. The breakdown of components used to arrive at the overall response time is 5.5 seconds for the RTD/thermowell and a conservative electronics delay of 1.0 second. The applicant stated that it will use the loop current step response (LCSR) test to measure RTD response time. A 10-percent allowance for LCSR test uncertainty will be used to ensure an overall channel response time of 7.0 seconds or less. ...During initial startup testing, actions will be taken to correct any resistance temperature detector (RTD) channel with an overall response time of greater than 7.0 seconds including electronics delay and a 10-percent allowance for loop current step response test uncertainty. After any such corrective action, the channel will be retested to verify an overall response time of 7.0 seconds or less (the value assumed in pertinent safety analyses). In 1997, licensee Design Change Notice (DCN) 39293 was implemented to increase the RTD response time. It stated, the response time requirement for OPT reactor trip was increased from 7 seconds to 8 seconds. This time includes RTDs, electronic processing, and trip circuit delays. As a result, the allowance for the sensor response time can be increased from 5.5 to 6.5 seconds. The Reactor Protection System Description, N3-99-1003, and the Technical Requirements Manual (TRM) were revised to reflect the change in response time for this channel. The change appeared to account for the 1.0 second electronic delay, but did not appear to account for the 10-percent allowance for LCSR test uncertainty, which would be derived from the RTD/thermowell delay. The uncertainty margin would appear to increase from 0.5 to 0.6 seconds. This change was implemented without NRC review and approval. In 2015, during hot functional testing of Unit 2 TAS RTDs, the RTD/thermowell delay did not meet the 6.5s required by the TRM from the change in 1997. On May 23, 2015, DCN 66327 was implemented to increase the response time again. The DCN stated, this DCN increases the total Narrow Range RTD response time from 8 to 9 seconds while changing the sensor response time from 6.5 to 8 seconds. Westinghouse has evaluated this change in letter WBT-D-5476 and determined that existing analyses are not impacted by this change. In this new response time the 1.0 second electronic delay and 8 second RTD/thermowells delay appeared to be accounted for, but not the margin for LCRS test uncertainty. If the 10-percent allowance for LCSR test uncertainty were accounted for, the total response time would appear to increase to 9.8 seconds. Westinghouse used a total response time of 9.0 seconds for their analyses at the direction of TVA, per WBT-TVA-3027, Revision 0, (5.10) PIN ELICB-055 Evaluation to Support a 9.0-second Total RTD Response Time, August 2015. The 10 percent LCSR uncertainty does not appear to have been included. Westinghouse letter LTR-TA-15-92, Transient Analysis Evaluation of an Increased RTD Delay Time for Watts Bar Unit 2, Rev. 0, stated, in part, due to the limiting nature of the (Steam Line Break) SLB w/ (Rod Withdrawal at Power) RWAP event, in which no margin currently exists to the departure from nucleate boiling ratio (DNBR) safety analysis limit (SAL), the inclusion of a 9.0-second total RTD response time resulted in a 0.55% DNBR penalty. For the feed water event, defined as a reduction in feedwater temperature, the Westinghouse letter stated, in part, key event results for both of the multiple-loop cases were impacted by the delay in receiving the OPT trip. While substantial margin was maintained to the DNBR limit of 1.38, the peak core heat flux values slightly exceeded the limit value of 121%. The letter concluded that the slower responding RTDs did not significantly impact the non-LOCA transient analyses and that the acceptance criteria for the events continued to be met, with the exception of the SLB w/ RWAP. However, generic DNB margin will be allocated to offset the 0.55% DNBR penalty associated with the evaluation. As such, the non-LOCA transient analyses can support operation of Watts Bar Unit 2 with a total RTD delay time of up to 9.0 seconds. The inspectors questioned the licensee to understand why the 10-percent allowance for LCSR test uncertainty was not accounted for in the Westinghouse analyses, and to what extent it could have affected the results. In addition, the inspectors questioned whether the 10-percent uncertainty was adequate in the current installation configuration. The inspectors also questioned how the LCSR test could account for increased thermal resistance between the RTDs and the thermowells. The test may not measure the actual delay time from the hot leg across the thermowell thermal resistance to RTD. The original installations relied on specific RTD thermowell bonding to establish a predictable thermal resistance and initial response time. It is unclear how this was performed for this installation to determine the actual response time. The 10 CFR 50.59 evaluation was performed May 22, 2016. This issue has been captured in the Corrective Action Program (CAP) as CR 1398934, Potential failure to request lic. amendment to change OPdT/OTdT response time
05000390/FIN-2018010-02	2018Q1	Watts Bar	Potential Failure to Perform a 50.59 Evaluation for Auxiliary Building and Containment Isolation	DCN 66459 added relays and wiring to change the actuation system that initiated the Auxiliary Building Isolation (ABI) and Containment Ventilation Isolation (CVI) protective functions. The new control elements (relay contacts and wiring) bypassed the Unit Solid State Protection System (SSPS) circuitry. The intent was to actuate the CVI function on an ABI actuation from the opposite unit while it was at full power operation and the other unit was in refueling mode. By bypassing the refueling units protection system and controlling the components in the refueling unit, the modification in effect made the protection systems (CVI) a shared system. The CVI was classified as part of the Engineered Safeguards Protection Systems (ESFAS). The ESFAS was not listed in the UFSAR Chapter 3.1.2 WBNP Conformance with GDCs (General Design Criteria), as shared systems under GDC 5. The UFSAR compliance with GDC 5 Sharing of Structures, Systems, and Components, specified all shared systems are sized for all credible initial combinations of normal and accident states for the two units, with appropriate isolation to prevent an accident condition in one unit from carrying into the other. The new control elements integrated in the ESFAS logic, apparently on both units. The licensee did not perform a failure modes and effects analysis to determine the negative effects that could degrade the ESFAS isolation functions when they are required to operate. The inspectors are concerned that the integration of the two ESFAS circuitry could have a detrimental effect. Additional failure modes appear to have been introduced into these systems. The inspectors need to determine the extent to which each units protection system and CVI were exposed to additional failures including common cause failures to determine whether there could be more than a minorissue and a potential failure to perform an adequate 50.59 evaluation in accordance with NPG-SPP-09.3 Plant Mods and Engineering Change Control, Section III, was a performance deficiency. This URI, is being opened to determine whether the PD is more than minor. This modification was complete on June 16, 2017. This issue was captured in CR 1398935, Potential violation of 10 CFR 50.59(d)(1) via DCN 66459.
05000390/FIN-2018010-03	2018Q1	Watts Bar	Potential Failure to Maintain Design Requirements of RTDs	The TAS RTD receipt documents specified design criteria identified in EQOP-ESE-7 in WCAP 8587 and the EQTR WCAP-8687 Supp. 2-E07A. The installed condition of the RTDs did not appear to meet the qualification performance specifications. Testing performed indicated that a gap existed between the RTDs and installed thermowells creating a large thermal resistance. Westinghouse document FDR-WBT-2015-01, Field Deviation Notice for Watts Bar Unit 2, indicated that the RTD/thermowell fit for the tip was outside the maximum tolerance listed in design drawing 1847E83 Rev. 4. The performance specifications were to ensure that the RTD time response across the thermowells thermal resistance was within tolerance. The higher thermal resistance increased the response time. The deviation appeared to be accepted as is. The Westinghouse equipment qualification data package, WCAP 8587/EQOP-ESE-7 Supplement 1 Rev. 7, page D1-5 Rev. 21, specified, in part that the performance requirements for the RTDs must meet +0.2"F repeatability; first order time response 5 seconds with well for step change of at least 20F with a water flow of 7 ft/sec. ...Time response testing has been successfully performed via type testing on a sample model of this RTD. The performance requirement appears to require a 5-second RTD/thermowell response time for qualification directly measured across the thermowell medium. The inspectors are concerned that the installed RTD/thermowell configuration was not verified to meet the performance requirements for qualification. It appeared that, due to the installation issues, the RTD response time increased, as measured by LCSR testing methods, the total delay time of 9.8 seconds. However, Westinghouse used a total response time of only 9.0 seconds for their analyses at the direction of TVA specification per WBT-TVA-3027, Revision 0, PIN ELICB-055 Evaluation to Support a 9.0-second Total RTD Response Time, August 2015. The analyses determined that some accident margins were impacted at 9.0 seconds. The inspectors questioned what the impact of the additional delay would have on the accident analyses and qualification. The inspectors questioned how the LCSR test method could accurately account for increased thermal resistance between the RTDs and the thermowells and whether the original 10-percent uncertainty for LCSR testing was adequate in the currently installed configuration. The validity of the LCSR method depends on how well the temperature sensor design satisfies LCSR test assumptions. The original installations relied on specific RTD thermowell bonding to establish a predictable thermal resistance and initial response time. It is unclear how the actual response time was determined this installation. This URI is being opened to determine if a PD exists. A review of documents and specifications provided by licensee indicated that new information requests would be likely. This issue has existed since September 2015. This issue was captured in CR 1398936, RCS Narrow Range RTDs Design and Qualification Requirements.
05000369/FIN-2018010-02	2018Q1	Mcguire McGuire	Failure to Update the FSAR With Pertinent Design Information	The inspectors identified a Green finding and associated Severity Level IV Non-cited Violation (NCV) of Title 10 of the Code of Federal Regulations (10 CFR) 50.71(e), for the licensees failure to update the final safety analysis report (FSAR) to include the design function of manually opening the residual heat removal (ND) system shutdown cooling suction valves. Consequently, the licensee failed to consider the design capability of the valves, time impacts on dose consequence analyses, and the implication of pressure locking.
05000269/FIN-2018013-01	2018Q1	Oconee	Failure to Translate Design and Licensing Basis Requirements and Verify Adequate Design	The licensee did not correctly translate site design and licensing bases into the site specifications and procedures for the design and installation of plant modifications that included the re-configuration of electrical cables in electrical cable trench #3 between the Keowee Hydro Station (KHS) and transformer CT-4 at Oconee Nuclear Station (ONS) and the Protected Service Water (PSW) ductbank between CT-4 and the PSW building. The specific requirements of IEEE 279-1968 and single failure sections of IEEE 279-1971 were not fully implemented. Contrary to this requirement, the licensee placed Class 1E 125Vdc system cables adjacent to various medium voltage-high energy alternating current (ac) power distribution cables for the offsite and onsite power systems and introduced credible single failure conditions with the potential for exposure of the onsite redundant Class 1E dc power distribution and control systems (dc systems) to possible damaging peak voltage from the offsite and onsite AC power systems. Corrective Actions: The licensee reported this as an unanalyzed condition to the NRC in accordance with 10 CFR 50.73(a)(2)(ii) (B) in Licensee Event Report 269/2014-01 entered this issue into their corrective action program. The licensee also performed immediate and prompt determinations of operability in which they concluded a reasonable expectation of operability existed on the basis that the consideration of the specific hazards was not required by the site licensing basis. A number of plant modifications were implemented to address the concerns.Additional inspections of these corrective actions will be conducted as appropriate. For the limited areas where the concerns could not be addressed, on February 28, 2018, (ML180051B257) the NRC granted relief from the applicable Code and concluded that the proposed alternatives provided an acceptable level of quality and safety for the cable configurations and locations.Corrective Action Reference: PIP O-14-03190, PIP O-14-05125, PIP O-14-03915, and PIP O-14-02965
05000269/FIN-2018013-02	2018Q1	Oconee	Failure to Submit for License Review andObtain a License Amendment for a Modification	The licensee procedure Nuclear System Directive (NSD): 209 10 CFR 50.59 Process, committed to using Nuclear Energy Institute (NEI) 96-07, Guidelines for 10 CFR 50.59 Implementation.The guidance in Nuclear Energy Institute (NEI) 96-07 Section 4.3.2, specified that if a change in likelihood of occurrence of a malfunction increases by more than a factor of two would need NRC approval, because certain changes that satisfy the factor of two limit exceed the minimal increase standard for accident/transient frequency under criterion 10 CFR 50.59(c)(2)(i). The guidance in NEI 96-07 Section 4.3.8, specified that the use of new or different methods of evaluation that are not approved by NRC for the intended application, such as the methods identified in the memo to File, ME Patrick (PJ North), dated 1/12/92, Single Failure Timing Licensing Basis, no file number given. (Note: Memo was actually written 1/12/93), would need NRC approval, because it was considered a departure from a method of evaluation described in the UFSAR. Based on this guidance, the team determined that the modifications associated with engineering changes (ECs), EC91880, Keowee Emergency Start Cable, revision 24 and EC91875, Keowee AC Power Supply Tie-Ins, revision 15, and EC91874, 13.8 KV Feed To PSW System from 100 KV APS, revision 7 would require NRC approval in accordance with 10 CFR 50.59(c)(2)Corrective Actions: TBDCorrective Action References: TBD
05000250/FIN-2010009-01	2010Q1	Turkey Point	Violation of Technical Specification 5.5.1.1 regarding Unit 3 spent fuel storage with degrading Boraflex Poison	A. TS 5.5.1.1.a states that the Unit 3 spent fuel storage racks are designed and shall be maintained with a Keff less than 1.0 when flooded with unborated water, which includes an allowance for biases and uncertainties as described in Chapter 9 of the UFSAR. Chapter 9 of the Turkey Point UFSAR states, in part, that the most limiting depletion of Boron-10 from the Boraflex fuel storage racks was a reduction of nominal Boron-10 areal density of 50 percent for Region II racks. Contrary to the above, the licensee failed to maintain the Unit 3 spent fuel storage racks such that Keff would remain less than 1.0 when flooded with unborated water when considering the biases and uncertainties described in Chapter 9 of the UFSAR. Specifically, licensee data indicates that dissolution of Boron-10 from Boraflex panels in Region II of the FPL 2 Turkey Point Unit 3 spent fuel pool resulted in a reduction in the nominal Boron-10 areal density in excess of 50 percent, such that Keff would not have been maintained less than 1.0 for all cases if the spent fuel pool had been flooded with unborated water. B. 10 CFR Part 50, Appendix B, Criterion XVI, Corrective Action, states, in part, that measures shall be established to assure that conditions adverse to quality are promptly identified and corrected. Turkey Point UFSAR page 9.5-12 states that the most limiting case obtained to assure Keff was equivalent to less than 1.0 in Region II was a reduction of Boraflex nominal areal density by 50 percent. Contrary to the above, a condition adverse to quality was not promptly identified and corrected. Specifically, in 2004 and 2007, the licensee identified two spent fuel pool storage cells with Boraflex degradation greater than an administrative action limit specified in Turkey Point Plant Curve Book, Section 5. However, the licensee failed to correct this condition adverse to quality until it was identified by NRC inspectors in December 2009. These violations are associated with a White Significance Determination Process finding for Unit 3 in the Initiating Events cornerstone
05000335/FIN-2010002-05	2010Q1	Saint Lucie	Licensee-Identified Violation	10 CFR 50, Appendix B, Criterion V, requires, in part, that activities affecting quality shall be prescribed by documented instructions or procedures, and shall be accomplished in accordance with these instructions or procedures. On January 6, 2010, with the onset of unusually cold weather (consecutive nights of temperatures in the low 40s), the licensee identified that safety-related procedure ADM-04.03, Cold Weather Preparations, had not been completed when it was discovered that the 2A1 EDG immersion heater power circuitry was not able to achieve the necessary current readings as called out in ADM-04.03. This resulted in Operations having to run the diesel several times over the course of a few days to ensure the lube oil temperatures remained above procedural limits, thus ensuring EDG operability. The finding was more than minor because it is similar to Example 2.f, of IMC 0612, Appendix E, Examples of Minor Issues, in that the failure to implement the cold weather procedure resulted in the immersion heaters inability to maintain lube oil temperatures above 85oF going undetected until the procedure was completed. The finding is of very low safety significance (Green) because the 2A EDG was capable of starting and performing its safety-related function. This issue was documented in the licensees CAP as CR 2010-286
05000335/FIN-2010002-04	2010Q1	Saint Lucie	Licensee-Identified Violation	10 CFR 50 Appendix B, Criterion V, states, in part, that activities affecting quality shall be prescribed by documented instructions, procedures, or drawings of a type appropriate to the circumstances and shall be accomplished in accordance with these instructions, procedures, or drawings. Contrary to the above, on March 19, 2009, the licensee determined that safetyrelated Administrative Procedure ADM-04.03, Colds Weather Preparations, did not provide adequate guidance to prevent the MFIVs temperature from going below 60 degree F during the winter months. All four MFIVs valves could have been inoperable longer than the required TS 3.7.1.6 allowable time in 2007 when the ambient temperature less than 60 degree F existed for a 22 hour period, with 39 degree F being lowest temperature. This condition had existed for a long time and was not apparent to the FPL staff. This was identified in the licensees CAP as CR 2008-15821. Since these valves would not have performed their safety function for greater than the TS allowed outage time, a SDP Phase 2 analysis was required. Using the SDP Phase 2 worksheets associated with MSLB, the finding is determined to have very low safety significance (Green) since all remaining mitigation capability was available
05000335/FIN-2010002-03	2010Q1	Saint Lucie	Licensee-Identified Violation	10 CFR 26.205(d) requires, in part, that individuals subject to work controls do not exceed 26 work hours in any 48-hour period and 72 work hours in any 7-day period; requires a 34-hour break in any 9-day period; and a 10-hour break between successive work periods. During the periods of November 29 to December 07, 2009, two workers did not have the 34-hour break in a 9-day period; and March 07 to March 15, 2010, one worker did not have the 34-hour break in a 9-day period. The violation occurred in two separate work groups being mechanical maintenance and operations (non-licensed operator). The licensee determined that the personnel involved did not have a firm understanding of the revised 10 CFR Part 26 requirements. The finding was more than minor because if left uncorrected, it would become a more significant safety concern. Specifically, the excessive work hours would increase the likelihood of human performance errors during plant maintenance activities that could affect equipment performance. The finding is of very low safety significance (Green) because no significant events or human performance issues were directly linked to personnel fatigue as a result of the hours worked. This issue was documented in the licensees corrective action program as condition reports 2009-34850 and 2010-6788
05000335/FIN-2010002-01	2010Q1	Saint Lucie	Untimely Corrective Actions for 2A1 EDG Immersion Heaters	The inspectors identified a Non-Cited Violation (NCV) of 10 CFR 50, Appendix B, Criterion XVI, Corrective Action, for failure to promptly identify and correct a condition adverse to quality for degraded wiring in the 2A1 EDG immersion heater power circuitry that resulted in low lube oil temperatures and required Operations to run the diesel several times over the course of a few days to ensure operability. The issue was entered into the CAP as CR 2010-3332. The finding was more than minor because it affected the equipment performance attribute of the mitigating systems cornerstone objective to ensure the availability, reliability, and capability of the 2A EDG to respond to initiating events to prevent undesirable consequences. SDP Phase 1 Screening indicated that the finding was of very low safety significance because it was not a design deficiency, nor did it result in an actual loss of system or single train function, nor did it screen as potentially risk significant due to external events. This finding has a cross-cutting aspect in the problem identification and resolution area of the corrective action program component because the licensee did not perform a thorough evaluation of problems such that the resolutions address causes and extent of conditions (P1.c) (Section 1R15)
05000335/FIN-2010002-02	2010Q1	Saint Lucie	Inadequate Procedure for Main Steam Isolation Valve Testing	A self-revealing non-cited violation (NCV) of 10 CFR Part 50, Appendix B, Criterion V, \"Instructions, Procedures, and Drawings,\" was identified when safety related surveillance test procedure 2-OSP-08.01, Main Steam Isolation Valves Periodic Test, was implemented as written in Mode 2 causing the main feed water isolation valves (MFIVs) to close resulting in a momentary loss of feed water to the steam generators. The surveillance procedure did not provide adequate initial conditions or special precautions to prevent plant conditions that would result in a loss of feed water to the steam generators. The issue was entered into the corrective action program (CAP) as condition report (CR) 2009- 29332. The finding was more than minor because it was similar to example 4.b in IMC 0612, Appendix E, in that it challenged steam generator water level control due to closure of the MFIVs and resulted in a feed flow transient. The finding was associated with the procedure quality attribute of the Initiating Events cornerstone and adversely affected the associated 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 finding was evaluated in accordance with IMC 0609, Attachment 4, and determined to be of very low safety significance per the Significance Determination Process (SDP) Phase 1 Screening because the finding did not contribute to both the likelihood of a reactor trip and the likelihood that mitigation equipment or functions would not be available, and did not screen as potentially risk significant due to external events. This finding has a cross-cutting aspect in the area of human performance because the licensee did not provide complete, accurate and up-to date procedures to plant personnel (H.2.c). (Section 4OA2.2
05000250/FIN-2010002-01	2010Q1	Turkey Point	Failure to implement design controls in a temporary modification.	The inspectors identified an NCV of 10 CFR 50, Appendix B, Criterion III, Design Control, for failing to maintain control of temporary equipment installed on unit 4 A residual heat removal pump piping when the permanent component cooling water flow indication to the pump seal failed high. Operators were using a controlotron as a compensatory measure to verify adequate cooling flow to the unit 4A residual heat removal pump seal and to assure operability of the unit 4A residual heat removal pump. If the controlotron had failed, the operators would not have received a component cooling water low flow alarm in the control room, lack of cooling flow to the pump would have gone undetected, and operability of the residual heat removal pump could have been affected. The inspectors identified the licensee failed to follow the temporary system alteration procedure to ensure design adequacy and to determine if the alteration required a 10 Code of Federal Regulations (CFR) 50.59 evaluation and NRC approval. The licensee documented this in the corrective action program as condition report 2010- 479. The finding is more than minor because it affected the configuration control attribute of the Mitigating Systems Cornerstone in that it reduced the reliability of the 4A residual heat removal pump with the permanent flow indicator out of service while using an unevaluated controlotron to determine continued operability of the 4A residual heat removal pump. The inspectors screened the finding using NRC Inspection Manual Chapter 0609, Significance Determination of Reactor Inspection Findings for At Power Operations, Phase 1 screening. The finding was of very low safety significance because the design or qualification deficiency did not result in actual loss of operability or functionality of the pump. The cross cutting aspect of Human Performance, Work Practices (H.4(b)) was affected. (1R18)
05000250/FIN-2010002-02	2010Q1	Turkey Point	Licensee-Identified Violation	Technical Specification 3.9.13 requires that with one containment radiation monitor out of service during core alterations, core alterations may continue as long as the containment ventilation isolation valves be maintained shut and within one hour, operate the control room ventilation system in the recirculation mode. Contrary to the above, on April 1, 2009, and on prior occasions, core alterations continued with one channel of control room isolation actuation out of service and without the control room ventilation in the recirculation mode. The non-compliance was identified during review of plant conditions while performing engineered safeguards integrated testing with the plant in Mode 6 refueling. The redundant radiation monitoring and actuation channel remained available and had an event occurred, operators would have been able to use standby Self-contained breathing apparatus (SCBA) assuring the safety function. The issue was screened to be of very low safety significance (Green). When identified, the licensee placed the control room in recirculation and isolated the ventilation valves. The issue was documented in condition report 2009-9899 and additional corrective actions were specified. Because the licensee identified the issue and documented it into their corrective action program, and because the finding is of very low safety significance, this violation is being treated as a licensee identified NCV consistent with Section VI.A of the NRC Enforcement Policy
05000302/FIN-2010002-02	2010Q1	Crystal River	Licensee-Identified Violation	The following issue of very low safety significance (Green) was identified by the licensee and was a violation of NRC requirements. This issue met the criteria of Section VI of the NRC Enforcement Policy, NUREG-1600, for being dispositioned as a non-cited violation. Improved Technical Specification (ITS) 3.7.1 states that MSSVs shall be operable as specified in ITS Table 3.7.1-1 in Modes 1, 2 and 3. Contrary to the above, on September 22, 2009, while performing SP-650, ASME Code Safety Valves Test, on the A OTSG in Mode 1, the as-found set points of three MSSVs were found outside the ITS 3.7.1 acceptance criteria of +/- 3 percent of the nominal set point. The valves were returned to operable status by adjusting their set point to within +/- 1 percent. The licensee concluded that the three MSSVs were inoperable for a period longer than allowed by plant ITS. The licensee determined that this ITS violation was a result of a failure, in past years when MSSVs were found out of tolerance, to provide adequate instructions to the vendor refurbishing the valves to determine the root causes of the out of tolerance condition. This lack of adequate vendor instructions was the result of the licensees failure to follow Corrective Action Program procedures which require that physical evidence and important information that is essential to identifying cause(s) be preserved. The finding was evaluated using Phase 1 of the At-Power SDP, and was determined to be of very low safety significance (Green) because the inspectors responded no to all questions in the mitigating systems cornerstone column of Table 4a, Manual Chapter 0609, Attachment 0609.04. This issue was documented in the licensees corrective action program as NCR 356521
05000302/FIN-2010002-01	2010Q1	Crystal River	Failure to Take Compensatory Actions When a MCR to CSR Floor/Ceiling Interface Access Hatch Was Open.	The inspectors identified a non-cited violation of Crystal River Unit 3 Operating License Condition 2.C.(9), for failure to take compensatory actions when a main control room (MCR) and cable spreading room (CSR) floor/ceiling interface access hatch was open rendering the CSR Halon fire extinguishing system inoperable. Once identified, the licensee initiated nuclear condition report (NCR) 266356 in the corrective action program to address this issue. The finding is more than minor because it is associated with the protection against external factors attribute, i.e., fire, and degraded the Mitigating Systems cornerstone objective to ensure the availability of systems that respond to initiating events. Specifically, the finding adversely affected the suppression fire extinguishing system capability defense-in-depth element. The inspectors evaluated this finding under NRC Inspection Manual Chapter (IMC) 0609, Appendix F, Fire Protection Significance Determination Process (SDP). The inspectors determined that a Phase 2 SDP was required for this finding because the CSR Halon concentration was highly degraded; a fire could occur due to non-qualified cables or transient combustibles while the hatch between the MCR and CSR was open; a duration factor (exposure time) was between 3 and 30 days; and control room operators evacuated the MCR in response to the fire. However, Phase 2 SDP of IMC 0609 Appendix F does not currently include explicit treatment of fires leading to MCR abandonment, either due to fire in the MCR or due to fires in other fire areas. Therefore, a Phase 3 SDP evaluation for this type of finding was needed. A Regional Senior Reactor Analyst performed a Phase 3 SDP for this finding and concluded that the finding was of very low safety significance (Green). The major assumptions and the dominant accident sequence were discussed in the 4OA5 analysis section of this report. The inspectors did not identify a cross-cutting aspect associated with this finding because it does not reflect current licensee performance.
05000250/FIN-2010008-01	2010Q1	Turkey Point	Failure to perform adequate written 50.59 evaluation.	The inspectors identified an AV of 10 CFR 50.59(d)(1) for failure to maintain records that include a written evaluation which provides the bases for the determination that a change, test, or experiment does not require a license amendment. Specifically, the licensee received NRC approval to make changes to the facility via license amendment No. 234 dated July 17, 2007, involving the design of the spent fuel pool storage racks, including the use of Metamic inserts and other hardware, administrative controls and testing methods, to assure that the spent fuel remains within design limits. Subsequent to the NRCs approval, the licensee determined that Metamic inserts could not be installed by the date approved by the NRC. However, the licensee maintained no written evaluation which provided the bases for the determination that the change to the design of the spent fuel pool storage racks, without the use of Metamic inserts, did not require a license amendment pursuant to paragraph (c)(2) of 10 CFR 50.59.The finding was more than minor because it impacted the regulatory process which depends on plant activities being properly evaluated and, when required, reviewed and approved by NRC. Because this finding impacted the regulatory process, it was evaluated using traditional enforcement and is being considered for escalated enforcement action in accordance with NRCs Enforcement Policy. The inspectors determined that the cross-cutting aspect of Human Performance, (H.4(c)) is applicable to this issue because the licensee did not ensure supervisory and management oversight of work activities, including contractors, such that nuclear safety is supported, when errors in administering Technical Specification requirements and programmatic controls which assure safety were not effectively implemented.
05000250/FIN-2010008-05	2010Q1	Turkey Point	Failure to maintain Keff per 10 CFR 56.68 and TS 5.5.1.1.a	The inspectors identified an AV of Technical Specification 5.5.1.1.a and 10 CFR50.68(b)(4) for failure to assure that the effective neutron multiplication factor (Keff) would be maintained equivalent to less than 1.0, for all cases in the Unit 3 spent fuel pool(SFP) when flooded with unborated water. The finding was more than minor because, if left uncorrected, the racks would continue to degrade further reducing the neutron absorption capability and become a more significant safety concern. In addition, the finding impacted the initiating event cornerstone objective of limiting events that challenge safety functions; for example, preventing criticality in an area not designed for criticality. Because probabilistic risk assessment tools were not suited for this finding, the inspectors evaluated the finding using IMC 0609, Appendix M, Significance Determination Process Using Qualitative Criteria. Because the Boraflex degradation resulted in a significant loss of margin to criticality, NRC management concluded the finding was preliminarily greater than Green. The inspectors determined that the cross-cutting aspect of Problem Identification and Resolution, (P.1(c)) is applicable to this issue because the licensee did not properly evaluate the problems associated with Boraflex degradation to assure operability and reportability was adequately addressed
05000250/FIN-2010008-03	2010Q1	Turkey Point	Failure to report SFP Boraflex degradation per 10 CFR 50.73	The inspectors identified an AV of 10 CFR 50.73(a)(2)(B), when a condition prohibited by Technical Specifications was not reported to the NRC after testing of Boraflex panels in 2004 in the Unit 3 spent fuel pool revealed degradation greater than assumed in criticality analyses. Because the FPL program for determining degradation of cells was a sampling program, the state of other cells could not be determined. When identified to the licensee by the NRC, condition report 2010-6254 was written to evaluate and report the non-compliance with Technical Specifications to the NRC. The finding was more than minor because it impacted the NRCs regulatory process, which relies on certain plant conditions being properly reported to the NRC. Because this finding impacted the regulatory process, it was evaluated using traditional enforcement and is being considered for escalated enforcement action in accordance with NRCs Enforcement Policy. No cross-cutting aspect associated with this issue was identified.
05000250/FIN-2010008-04	2010Q1	Turkey Point	Failure to update the FSAR to reflect SFP management practices	The inspectors identified an AV of 10 CFR 50.71(e) for failure to update the Final Safety Analysis Report (FSAR) so that the report accurately reflects significant changes made to the facility. As of December 2009, changes made to manage the Unit 3 spent fuel pool since 2001, including the use of alternate means of assuring that the spent fuel remains shutdown such as use of rod control cluster assembly inserts and water holes, use of neutron attenuation testing methods and results, and use of computer programs such as RACKLIFE, were not described in the Updated FSAR. When identified to the licensee by the inspectors, the licensee documented the condition in condition report 2009-34470, and informed the NRC (in letter L-2009-295, dated December 31, 2009) of plans to make appropriate updates to the FSAR descriptions by March 15, 2010.The finding was more than minor because it impacted the regulatory process, which relies on licensees properly maintaining their FSAR up to date. Because this finding impacted the regulatory process, it was evaluated using traditional enforcement and is being considered for escalated enforcement action in accordance with NRCs Enforcement Policy. No cross-cutting aspect associated with this issue was identified.
05000250/FIN-2010008-02	2010Q1	Turkey Point	Failure to correct Boraflex degradation in the SFP in a timely manner	The inspectors identified an AV of 10 CFR Part 50, Appendix B, Criterion XVI, Corrective Action, for failure to effectively correct a condition adverse to quality involving degradation of Boraflex neutron absorber material in the Unit 3 SFP, such that in November 2009 two spent fuel pool storage cells L38, F19 with Boraflex degradation greater than that assumed in the criticality analyses had been allowed to remain inservice even after the licensee had revised SFP management controls. When brought to the attention of the licensee by the NRC, condition report 2009-34470 was written to document the non-compliance. The finding was more than minor because, if left uncorrected, it would become a more significant safety concern since it could not be determined if other, untested storage rack locations could be more degraded. In addition, the finding impacted the initiating event cornerstone objective of limiting events that challenge safety functions; for example, preventing criticality in an area not designed for criticality. Because probabilistic risk assessment tools were not suited for this finding, the inspectors evaluated the finding using IMC 0609, Appendix M, Significance Determination Process Using Qualitative Criteria. Because the Boraflex degradation resulted in a significant loss of margin to criticality, NRC management concluded the finding was preliminarily greater than Green. The inspectors determined that the cross-cutting aspect of Problem Identification and Resolution (P.1(d)) is applicable to this issue because the licensee did not implement effective corrective action for degradation of Boraflex neutron absorber material
05000250/FIN-2010009-02	2010Q1	Turkey Point	Failure to report Unit 3 spent fuel pool operation with degrading Boraflex.	The inspectors identified an apparent violation of 10 CFR Part 50.73(a)(2)(B), when a condition prohibited by Technical Specifications was not reported to the NRC after testing of Boraflex panels in 2004 in the Unit 3 spent fuel pool revealed degradation greater than assumed in criticality analyses. Because the FPL program for determining degradation of cells was a sampling program, the state of other cells could not be determined. When identified to the licensee by the NRC, condition report 2009-30043 was written to evaluate and report the non-compliance with Technical Specifications to the NRC. The finding was more that minor because it impacted the regulatory process which depends on plant activities being properly reported. The inspectors evaluated this finding against NRC IMC 0609 Phase 1 Screening Worksheet for Initiating Events, Mitigation Systems, and Barriers Cornerstones. The inspectors determined that IMC 0609, Appendix M is required to determine the level of safety significance of this finding because the existing SDP guidance is not adequate to provide reasonable estimates of the finding significance within the established SDP timeliness goal of 90 days. NRC staff is currently reviewing this finding to determine the level of safety significance or enforcement aspect of the issue. (4OA2) (IR# 05000250, 251/2009005 dated January 28, 2010) FPL failed to provide notification to the NRC in accordance with the requirements of 10 CFR 50.73 when testing and evaluation of Boraflex panels in the Unit 3 SFP racks revealed Boraflex degradation beyond minimum design values specified in the UFSAR. The NRC considers the failure to provide the required notification to be a significant matter because it impacted the NRCs ability to review and assess FPLs corrective actions for managing SFP Boraflex degradation. In accordance with the Enforcement Policy, a base civil penalty in the amount of $70,000 is considered for a Severity Level III violation. (IR# 05000250/2010009 dated June 21, 2010
05000250/FIN-2010009-03	2010Q1	Turkey Point	Failure to maintain FSAR description of Unit 3 spent fuel pool activities	The inspectors identified an apparent violation of 10 CFR Part 50.71(e) requirements to periodically update the final safety analysis report so that the report contains effects of changes made to the facility such that the FSAR is complete and accurate. As of December 2009, changes made to manage the Unit 3 spent fuel pool since 2001, including neutron attenuation testing methods and results, use of computer programs such as RACKLIFE, and the use of alternate means of assuring that the spent fuel remains shutdown, such as rod control cluster assembly inserts and water holes, were not described in the FSAR. When identified to the licensee by the inspectors, the licensee documented the condition in condition report 2009-34470, and informed the NRC (in letter L-2009-295, dated December 31, 2009) of plans to make appropriate updates to the FSAR descriptions by March 15, 2010. The finding was more that minor because it impacted the regulatory process which depends on plant activities being properly documented. The inspectors evaluated this finding against NRC IMC 0609 Phase 1 Screening Worksheet for Initiating Events, Mitigation Systems, and Barriers Cornerstones. The inspectors determined that IMC 0609, Appendix M is required to determine the level of safety significance of this finding because the existing SDP guidance is not adequate to provide reasonable estimates of the finding significance within the established SDP timeliness goal of 90 days. NRC staff is currently reviewing this finding to determine the level of safety significance or enforcement aspect of the issue. (4OA2) (IR# 05000250, 251/2009005 dated January 28, 2010) A Non-cited Violation 05000250/201009-03 was identified for failure to update the FSAR in accordance with 10 CFR 50.71(e) so that the report accurately reflects significant changes made to the facility. (IR# 05000250/2010009 dated June 21, 2010).
05000250/FIN-2009005-01	2009Q4	Turkey Point	Failure to Implement Required TS Controls for a High Radiation Area with Dose Rates in Excess of 1000 mrem/hr	A Self-revealing Non-cited Violation of Technical Specification (TS) 6.12.2, was identified for failure to meet high radiation area (HRA) control requirements for an accessible location, i.e., Unit 4 (U4) reactor auxiliary building (RAB) roof, with radiation levels greater than 1000 millirem per hour (mrem/hr) during refueling activities. Specifically, on November 3, 2009, general area dose rates exceeding 1000 mrem/hrwere identified outside of an established HRA posted barricade on the RAB roof adjacent to the outside wall of the Spent Fuel Pool (SFP) building. The HRA posted barricade, i.e., locked-HRA (LHRA) barrier, was established to delineate an area outside of which dose rates would not exceed 1000 mrem/hr. The licensee documented this issue in condition report (CR) 2009-31494.The finding was more than minor because it affected the Program and Process(exposure control) attribute of the Occupational Radiation Safety cornerstone and the failure of the licensee to implement proper HRA controls which could have led to unanticipated worker exposures. The inspectors evaluated the finding using the Occupational Radiation Safety Significance Determination Process and determined the issue to be of very low safety significance (Green) based on High Radiation Area controls in place for the subject area. The cross-cutting element of Human Performance, Decision-Making (H.1(b)) was affected when the licensee failed to conduct adequate radiological surveys needed to demonstrate compliance with TS HRA requirements for locations potentially having dose rates exceeding 1000 mrem/hr during current Unit 4 refueling activities (2OS1)
05000302/FIN-2009005-02	2009Q4	Crystal River	Manual Reactor Trip Due to Group 7 Control Rods Insertion Caused by Inadequately Protected Test Jumper	A self-revealing NCV of Improved Technical Specification (ITS) 5.6.1.1.a was identified for the failure to follow the provisions of preventative maintenance procedure PM-126, Electrical Checks of CRD (Control Rod Drive) Power Train. Failure to follow PM-126 caused the failure of the Group 7 control rod programmer during maintenance and resulted in the unexpected insertion of the Group 7 control rods fully into the core. This unexpected insertion of these control rods into the core caused control room operations personnel to manually trip the reactor from 100 percent power. The licensee entered this issue into the corrective action program as NCR 351705. This finding was determined to be more than minor because it was associated with the initiating events cornerstone attribute of Human Performance, and adversely affected the cornerstone objective to limit the likelihood of those events that upset plant stability and challenge critical safety functions during at-power operations. The finding was evaluated using Phase 1 of the At-Power SDP, and was determined to be of very low safety significance (Green) because it did not contribute to both the likelihood of a reactor trip and the likelihood that mitigating equipment or functions were not available. The cause of this finding was directly related to the cross-cutting area of Human Performance with a work practices aspect (H.4 (b)). Specifically, the workers failed to follow the preventative maintenance procedure
05000302/FIN-2009005-03	2009Q4	Crystal River	Licensee-Identified Violation	The following issue of very low safety significance (Green) was identified by the licensee and was a violation of NRC requirements. This issue met the criteria of Section VI of the NRC Enforcement Policy, NUREG-1600, for being dispositioned as a Non-Cited Violation. 10 CFR 26.205(d) requires, in part, that individuals subject to work hour controls do not exceed 26 work hours in any 48-hour period and 72 work hours in any 7-day period; requires a 34-hour break in any 9-day period; and a 10-hour break between successive work periods. During the period of October 12 to October 19, 2009, one worker exceeded 26 hours in a 48-hour period; nine workers exceeded 72 hours in a 7-day period; five workers did not have a 34-hour break in a 9-day period; and two workers did not have the required 10-hour break between successive work periods. The violation was limited to one work group, Florida Transmission Personnel, who were on-site to support outage work. The licensee determined that the Transmission personnel did not have a firm understanding of the revised 10 CFR Part 26 requirements. The finding was more than minor because, if left uncorrected, it would become a more significant safety concern. Specifically, the excessive work hours would increase the likelihood of human performance errors during plant maintenance activities that could affect equipment performance. The finding is of very low safety significance because no significant events or human performance issues were directly linked to personnel fatigue as a result of the hours worked. This issue was documented in the licensees corrective action program as NCR 361777
05000302/FIN-2009005-01	2009Q4	Crystal River	Failure to Follow a Plant Procedure Resulted in an Inoperable HPI System	A self-revealing Non-Cited Violation (NCV) of Improved Technical Specification (ITS) 5.6.1.1.a was identified for the failure to follow a plant procedure which resulted in a loss of a 480 volt engineered safeguards motor control center (ES MCC)-3B1. Concurrent with pre-existing conditions, the high pressure injection (HPI) system was declared inoperable and ITS 3.0.3 was entered for a period of one hour and 24 minutes. The licensee entered this issue into the corrective action program as nuclear condition report (NCR) 333515. The finding was more than minor since it affected the equipment availability attribute of the mitigating system cornerstone and resulted in ITS 3.0.3 entry for the HPI system being inoperable. The finding was evaluated against NRC Phase 1 Significance Determination Process (SDP) and Phase 2 SDP was required due to a loss safety function of the HPI system. A Regional Senior Reactor Analyst performed a Phase 3 SDP evaluation and concluded this finding was of very low safety significance (Green). The major assumptions of the evaluation were that the HPI function was out of service for exposure period (1 .5 hours) and there would be no recovery of the de-energized motor control center. The dominant accident sequence involved a support system failure of the Emergency Feedwater (EF) Indication and Control System rendering Main Feedwater and automatic control of EF unavailable, operators were unable to manually control EF flow causing its failure and with the HPI function lost due to the performance deficiency, core damage ensued. The inspectors determined the cause of the finding is related to the cross-cutting area of Human performance with a work practices aspect H.4 (c)). Specifically, work scope changes involving safety-related equipment did not receive the appropriate level management oversight resulted in a plant procedural violation
05000335/FIN-2009005-01	2009Q4	Saint Lucie	Inadequate Safety-Related Maintenance Procedure to Properly Align the 2B2 Reactor Coolant Pump/Motor Shaft Coupling Assemblies	An inspector identified non-cited violation of Technical Specification 6.8.1.a and Regulatory Guide 1.33 was identified for an inadequate safety-related maintenance procedure. Specifically, the inspectors identified that during reassembly of Reactor Coolant Pump (RCP) 2B2 in July 2009 mechanical maintenance procedure MMP-01.17, Reactor Coolant Pump Model N-9000 Seal Removal and Installation, Revision 10, instructed the licensee to utilize a method of checking the RCP coupling alignment that was not in accordance with Byron Jackson Technical Manual 741-N-0001/4, Revision 23. The procedure instructed the maintenance workers to measure the shaft coupling flange face gap clearance rather than measuring the concentricity/runout of the coupling flanges as required in the subject vendor technical manual. This resulted in the RCP running with increased vibrations and ultimately requiring a plant shutdown to perform repairs. This issue was entered into the Corrective Action Program (CAP) as Condition Reports 2009-28512 and 2009-22728 This finding is more than minor because it is associated with procedure quality attribute and affected the objective of the Reactor Safety/Initiating Event Cornerstone to limit the likelihood of those events that upset plant stability and challenge critical safety functions during shutdown as well as power operations. Specifically, the subject RCP maintenance procedure did not require the measurement of coupling run-out whenever the coupling is disassembled in accordance with the vendor technical manual requirements which resulted in an unplanned plant shutdown. The finding was determined to be of very low safety significance since it did not contribute to both the likelihood of a reactor trip and that mitigation equipment or functions would not be available. The inspectors determined that the cause of this finding has a crosscutting aspect in the area of human performance associated with the resources attribute, in that the maintenance procedure instructions were not complete or accurate to ensure proper RCP coupling alignment. (IMC 0305 aspect H.2.c)
05000335/FIN-2009004-03	2009Q3	Saint Lucie	Failure to take timely and effective corrective actions to prevent recurrence of EDG Day Tank level switch failures.	A self-revealing Non-Cited Violation (NCV) of 10 CFR 50, Appendix B, Criterion XVI, Corrective Action, was identified for failure of the licensee to take timely and effective corrective actions to prevent recurrence of Unit 1 emergency diesel generator (EDG) day tank level switch failures following identification of Murphy switch reliability issues and issuance of NRC NCV 05000335/2009002-02. Specifically, on July 19, 2009, during functional testing of the 1B EDG day tank level switches, both the low and low-low level Murphy switches failed. The finding is more than minor because it is associated with the equipment performance attribute of the mitigating systems cornerstone. The finding was previously determined to have very low safety significance based on an SDP Phase 3 analysis. The analysis determined that the risk was less than 1E-6/year. This finding was related to the corrective action attribute of the problem identification and resolution cross-cutting area in the aspect of appropriate and timely corrective actions (IMC 0305 aspect P.1.d). (Section 4OA2.3
05000302/FIN-2009004-01	2009Q3	Crystal River	Inadequate Risk Assessments When Performing Surveillance Testing	The inspectors identified a non-cited violation (NCV) of 10 CFR 50.65(a)(4) for the failure to perform adequate risk assessments associated with a number of surveillance tests. Specifically, it was determined that risk assessments were not being properly performed for equipment that became unavailable as a result of surveillance testing. This condition has existed since implementation of the Equipment out of Service (EOOS) risk assessment software more than 10 years ago. Short term corrective actions include performance of additional peer reviews of upcoming performance and surveillance tests (PTs and SPs) to ensure they are included in the plant risk assessment and a similar independent review by the corporate probabilistic risk assessment staff. Long term corrective actions include: screen all SPs and PTs to evaluate for risk impact; develop a methodology to include risk significant SPs and PTs in the plant risk assessment, either automatically from the work schedule or a manual process; incorporate risk assessment process changes in licensee procedures; and provide additional EOOS training to the plant staff. Utilizing IMC 0612, Appendix B, Issue Screening, the finding was determined to be more than minor since licensee risk assessments failed to consider risk significant systems and support systems that were unavailable during maintenance. In order to determine the risk significance of this finding, the inspectors selected two recently performed surveillance procedures for two high risk systems that were not included in the licensees risk assessment. The SPs selected were decay heat system (DHR) SP-340B, DHP-1A, BSP-1A and Valve Surveillance and emergency feedwater (EFW) system SP-146A, EFIC Monthly Functional Test (During Modes 1, 2, 3). The risk deficit for SP-340B was determined to be less than 1E-6 incremental core damage probability deficit (ICDPD). The risk associated with SP-146A was not quantified since it was determined that the system did not lose its functionality during the SP. Utilizing IMC 0609, Appendix K, Maintenance Risk Assessment and Risk Management Significance Determination Process (SDP), Flow Chart 1, the finding was determined to be of very low safety significance. This finding was not assigned a cross cutting aspect since the issue existed for greater than 10 years and is not indicative of current licensee performance
05000335/FIN-2009004-02	2009Q3	Saint Lucie	2B2Reactor Coolant Pump Failed Seal Injection Line	On July 8, 2009, during mid-shift operation, a Reactor Coolant System (RCS) Inventory Balance was performed and a 0.065 gpm RCS unidentified leak rate was calculated. Additionally, a Containment Atmosphere Particulate Radiation Monitor indicated an upward trend. The licensee performed a robotic inspection of containment in an attempt to identify any RCS leaks before shutting the unit down on July 13, 2009. Further investigation verified RCS pressure boundary leakage at the lower cavity piping J-groove weld of the 2B2 Reactor Coolant Pump (RCP). The licensee entered this issue into the Corrective Action Program (CAP) as CR 2009-19624. The licensees immediate corrective action included replacing seal packages to reset fatigue usage at the J-groove welds, flange removal, cutting and capping of the upper cavity lines and replacing middle cavity piping between the flange and next piping flange. To conduct repairs, the licensee entered into a higher risk Plant Operating Status (POS) of mid-loop configuration with reduced inventory. The inspectors noted that potentially similar weld failures took place in August 2007, on the 2B1 RCP pipe-to-elbow weld on the outboard side of the first flanged coupling of the 2B1 RCP seal injection 34 inch diameter line; in December 2007, on the 2B2 RCP weld connecting the 34 inch diameter seal injection line with the seal housing; and in January, 2009, on the 2B1 RCP pipe-to-flange weld on the outboard side of the first flanged coupling of the upper cavity pressure sensing line. The inspectors remained concerned whether licensee corrective actions associated with the previous weld failures were appropriate considering the repetitive failures. This issue is unresolved pending completion of NRC review and analysis of the final root cause evaluation and is identified as URI 05000389/2009004-02, Reactor Coolant Pump Failed Seal Injection Line. This LER is open
05000250/FIN-2009004-01	2009Q3	Turkey Point	Licensee-Identified Violation	Technical Specification Table 3.3-1, functional Unit 20, requires the reactor trip system trip logic to be operable. Technical specification 3.0.3 requires that action be taken within one hour to place the unit in Hot Standby within the next six hours. Contrary to the above, for the period from July 14 2008, until October 11, 2008, reactor trip system logic for undervoltage protection was not operable, and action was not taken to shutdown the unit as required. When discovered on October 11, 2008, an investigation was initiated, the reactor protection trip logic circuitry was altered and relays were replaced to restore the system to an operable configuration. The issue was documented in the licensees corrective action program as Condition Report 2009-28058. This finding was of very low safety significance because redundant reactor protection features remained available to assure safety should an undervoltage condition occur
05000250/FIN-2009004-02	2009Q3	Turkey Point	Licensee-Identified Violation	Technical Specification 3.6.4 requires each containment isolation valve be Operable or, Either restore the valve to operable status or isolate the affected penetration within 4 hours by use of at least one closed manual valve. Contrary to the above, on June 1, 2008, secondary system containment isolation valve CV-3-6275C failed a stroke test, was declared inoperable, and the affected penetration was not closed within 4 hours as required. When identified by the licensee during investigation of the failed test, on June 9, Technical specification 3.6.4 was invoked and the penetration was isolated by closing a manual isolation valve. The issue was documented in the corrective action program as CR 2008-18474. The finding was of very low safety significance because manual isolation of the penetration remained available, if needed in an event, and redundant mitigating trains of auxiliary feedwater remained available
05000335/FIN-2009004-01	2009Q3	Saint Lucie	Seat leakage of Containment Spray Valves 2MV-07-3/4	While reviewing condition report 2007-41688, the inspectors determined that seat leakage past containment spray system isolation valves 2-MV-07-3 and 2-MV-07-4 dates back to 1990. The valves are Pacific 12 inch gate valves with SB-0 Limitorque motor operators. Leakage has been as high as 3.37 gpm measured in 2004. Repairs on the valve seats and wedges have been ineffective. The repair activities have mainly consisted of lapping the valve seating surfaces and performing a satisfactory blue dye check. The valves are not containment isolation valves and require no periodic in-service test. The licensee has repeatedly planned replacement of the valve with an updated flexible wedge style valve during multiple refueling outages. However, as the refueling outages approach, the repair is cancelled due to scheduling conflicts or to further evaluate the condition. This has been noted by the inspectors during the last two refueling outages as the operator work around remains active. The inspectors determined that in 1996, the licensee developed a compensatory measure and procedure change to install a temporary hose from a drain valve downstream of 2-MV-07-3/4 to allow the seat leakage to drain to the floor drain system in the auxiliary building vice leaking into the containment spray system and discharging down into containment during shutdown cooling operations. Essentially, the licensee has created an operator work around that could have an adverse effect on shutdown cooling operations and reactor coolant system inventory while in midloop conditions which requires frequent makeup to the RCS to maintain reactor vessel inventory and adequate net positive suction head (NPSH) on the operating pump. This issue is unresolved pending completion of NRC review and analysis of licensee actions associated with the operator work around and is identified as Unresolved Item (URI) 05000389/2009-004-01, Seat Leakage of Containment Spray Valves 2 MV-07-3 and 2 MV-07-4
05000250/FIN-2009003-07	2009Q2	Turkey Point	Failure to Implement TS Requirements Regarding Structural Integrity of Code Class 2 Main Steam Isolation Components	The inspectors identified a Non-cited violation of TS 3.4.10 requirements on Unit3 regarding required components, when plant operation continued although a structural flaw in Class 2 main steam isolation valve steam trap piping had been identified. As a result of using an incorrect drawing in assessing the leak, plant operation continued although a plant shutdown should have been initiated. The licensee documented this in CR 2009-15284.The finding was more than minor because it affected the RCS equipment and barrier performance attribute of the Barrier Integrity cornerstone and the un-isolable through wall leak challenged the integrity of the main steam system for isolating steam generator tube ruptures. Using Manual Chapter 0609, Attachment 0609.04, Phase 1 screening, this finding was determined to be of very low safety significance because all containment barrier characterization answers marked as No. The cross-cutting element of Human Performance, Decision Making, Conservative Assumptions & Safe Actions (H.1 (b)) was affected when the licensee did not use conservative assumptions in evaluating a Class 2component flaw and its TS implications, and did not demonstrate that continued operation with the crack was safe in order to proceed
05000335/FIN-2009003-02	2009Q2	Saint Lucie	Failure to Follow Procedure When Placing Shutdown Cooling In-Service	A self-revealing NCV of Technical Specification (TS) 6.8.1.a and Regulatory Guide (RG) 1.33 was identified for the licensee failing to implement a written procedure for general plant operations. The normal operating procedure 2-NOP-03.05, Shutdown Cooling, was not implemented as written when drain valve V7207was mistakenly closed by a non-licensed building operator when it was required to be open when placing the A shutdown cooling train in service. Specifically, the closing of valve V7207 removed a required drain path for known valve seat leakage past containment spray boundary valve 2-MV-07-03 which resulted in unplanned adjacent intersystem leakage into the containment spray system from the reactor coolant system. This issue was entered in the licensees corrective action program as CR2009-15198.The finding was more than minor because it affected the Configuration Control attribute of the Initiating Events cornerstone and the valve misposition could be reasonably viewed as a precursor to a significant event. Using the NRC Manual Chapter 0609, A Significance Determination Process,@ Appendix G, Shutdown Operations Significance Determination Process, Checklist 3, the finding was determined to be of very low safety significance because Core Heat Removal, Inventory Control, Power Availability, Containment Control, and Reactivity Guidelines were all met. A contributing cause of the finding is related to the cross-cutting area of Human Performance, with a work practices component. Specifically, the operator failed to implement expected human error prevention techniques such as procedure place keeping and self-checking to ensure the valve was positioned properl
05000335/FIN-2009003-01	2009Q2	Saint Lucie	Inadequate Risk Assessment When Performing Weekly Pump Venting	The inspectors identified NCV of 10 CFR 50.65 (a)(4) when the licensee did not perform an adequate risk assessment which resulted in an underestimation of the associated risk while performing weekly Emergency Core Cooling System (ECCS)pump venting. On April 20, 2009, the inspectors were reviewing the Unit 2 control room chronological logs and noted that during the weekly High Pressure Safety Injection (HPSI) pump venting, the assessed risk using the Online Risk Monitor(OLRM) was recorded as green (low) instead of the required yellow (medium).During the venting evolution, the HPSI pump hand switch is taken to STOP rendering the pump incapable of performing its safety-related function to automatically inject water into the RCS, thereby requiring entry into the associated TS Action Statement and yellow OLRM risk determination. The issue was entered in the licensees corrective action program as CR 2009-12037.The finding was more than minor because it affected the Human Performance attribute of the Mitigating Systems cornerstone and using MC 0612, Appendix E, Example 7.e, because if the overall risk had been correctly assessed, it would have placed both units into a higher risk category. The finding was evaluated in accordance with MC 0609, Appendix K, Maintenance Risk Assessment and Risk Management Significance Determination Process (SDP), and determined to be of very low safety significance (Green), using Flowchart 1. This determination was based on the incremental core damage probability deficit being less than 1E-6 for the given condition of the HPSI pumps being out of service during the weekly pump venting. This finding has a crosscutting aspect in the area of human performance, component of work control because the licensee did not incorporate appropriate risk insights when planning maintenance that effects the OLRM value.

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