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05000389/FIN-2018003-012018Q3Saint LucieFailure to meet the Transient Combustible Requirements Specified by NFPA 805The inspectors identified a Green non-cited violation (NCV) of 10 CFR 50.48(c), National Fire Protection Standard NFPA 805, requirements. Specifically, the licensee failed to comply with transient combustible control requirements in high risk fire zones as required by NFPA 805 and implemented by licensee procedure ADM-19.03, Transient Combustible Control.
05000390/FIN-2018003-012018Q3Watts BarConfiguration Control Error Results in Actual Auxiliary Building Internal Flooding EventA self-revealed Green finding and associated NCV of Technical Specification (TS) 5.7.1, Procedures, was identified when the licensee failed to maintain adequate configuration control in the high pressure fire protection (HPFP) system in accordance with station configuration control procedure, NPG-SPP-10.2, Clearance Procedure to Safely Control Energy. Specifically, the licensee failed to restore HPFP system vent and drain valves to their appropriate configuration prior to returning the system to service which resulted in a significantly large amount of HPFP system water (on the order of 10,000 gallons) being introduced into many areas (including all levels) of the Unit 1 side of the auxiliary building and wetting numerous structures, systems, and components (SSCs) (including cables, ventilation ducts, motor-operated valves, etc.)
05000391/FIN-2018003-022018Q3Watts BarUnauthorized Entry Into a High Radiation AreaA self-revealed Green finding and associated NCV of TS 5.11.1.e was identified when the licensee failed to maintain current survey information and failed to inform a worker of increased dose rates in a high radiation area. As a result, a worker received an electronic dosimeter alarm on the Unit 2 pressurizer platform due to changing radiological conditions associated with a reactor mode change.
05000390/FIN-2018003-032018Q3Watts BarFailure to Collect Compensatory Samples for an Out-of-Service Effluent MonitorThe inspectors identified a Green finding and associated NCV of TS 5.7.2.3 when the licensee failed to take compensatory samples in accordance with Table 1.1-1 of the Offsite Dose Calculation Manual when the Unit 1 steam generator blowdown effluent monitor was out of service. Specifically, radiation monitor 1-RM-90-120/121 was inoperable from April 27 to May 27, 2018, and compensatory samples were not collected and analyzed within the required frequency of at least once per 24 hours.
05000391/FIN-2018003-042018Q3Watts BarInadequate Sensitive Equipment Control Results in Unit 2 Reactor Trip on April 12, 2018A self-revealed Green finding and associated NCV of Title 10 of the Code of Federal Regulations (CFR) Part 50, Appendix B, Criterion V, Instructions, Procedures, Drawings, was identified for the licensees use of a procedure that was not appropriate to the circumstances, which led to the conduct of improperly planned maintenance on sensitive equipment, ultimately resulting in a reactor trip. Specifically, an inadequacy was identified in station procedure 0-TI-12.10, Control of Sensitive Equipment, which lists the sensitive equipment defined, in part, as equipment that could cause a unit trip, on which work activities are required to be appropriately planned and conducted in a manner that will preclude a unit trip. The procedure did not list the high side reactor coolant system loop flow transmitter common drain line as sensitive equipment, which allowed the licensee to improperly perform maintenance on it without the appropriate planning and control necessary to preclude the Unit 2 reactor trip that occurred on April 12, 2018.
05000390/FIN-2018003-052018Q3Watts BarLicensee-Identified ViolationThis violation of very low safety significance was identified by the licensee and has been entered into the licensees corrective action program and is being treated as a non-cited violation, consistent with Section 2.3.2 of the Enforcement Policy. Watts Bar Nuclear Plant (WBN) Unit 1 Operating License Number NPF-90, Condition 2.F, requires, in part, that TVA shall implement and maintain in effect all provisions of the approved Fire Protection Program as described in the Fire Protection Report for the facility, as approved in Appendix FF Section 3.5 of Supplement 18 and Supplement 29 of the SER (NUREG-0847). The WBN Fire Protection Report was developed for WBN to ensure compliance with the requirements of this license condition. Fire Protection Report, Part II, is the Fire Protection Plan. The Fire Protection Plan, Section 14, Fire Protection Systems and Features Operating Requirements (ORs), Subsection 14.10, Fire Safe Shutdown Equipment, paragraph 14.10.4, requires a fire watch to be established in auxiliary building room 757-A10 within one hour of closing pressurizer block valve 1-FCV-68-332-B. Contrary to the above, on July 19, 2018, the licensee failed to establish a fire watch in auxiliary building room 757-A10 within one hour of closing pressurizer block valve 1-FCV-68-332-B.
05000390/FIN-2018003-062018Q3Watts BarLicensee-Identified ViolationThis violation of very low safety significance was identified by the licensee and has been entered into the licensee corrective action program and is being treated as a non-cited violation, consistent with Section 2.3.2 of the Enforcement Policy. Violation: Watts Bar Unit 1 TS 3.8.1, AC Sources - Operating, Condition A, requires, in part, that an inoperable required offsite circuit be restored to operable status within 72 hours. Contrary to the requirements of Technical Specification 3.8.1, a required offsite circuit was determined to be inoperable from May 27, 2017, to June 2, 2017.
05000390/FIN-2018003-072018Q3Watts BarLicensee-Identified ViolationThis violation of very low safety significance was identified by the licensee and has been entered into the licensee corrective action program and is being treated as a non-cited violation, consistent with Section 2.3.2 of the Enforcement Policy. Violation: Watts Bar Unit 1 TS LCO 3.8.7, Inverters-Operating, requires that two inverters in each of the four channels shall be operable. Contrary to the above, the licensee failed to ensure that two inverters in each of the four channels were operable. Specifically, from April 9, 2017 to January 10, 2018 inverter 1-II was inoperable due to an unqualified class 1E capacitor associated with the inverter.
05000335/FIN-2018001-012018Q1Saint LucieImproper Evaluation of LCV-9005 position setpoints Leads to AFASOn November 19, 2013, during reactor startup activities, feedwater bypass valves, A (LCV-9005) and B (LCV-9006), were found to be operating at different throttle positions while maintaining their respective steam generator water levels. Valves LCV-9005 and 9006 were both originally installed in April 1978. LCV-9005 was replaced in 1994, with an equivalent valve, due to obsolescence. The original valve had a full open stroke length of 1.5 inches (in.), while the new equivalent valve had a full open stroke length of 2 in. to provide the same flow as the original valve. When installed, LCV-9005 was set up to limit its stroke length to 1.5 in., matching the replaced valve, and the associated drawings were never revised to show that the new valve had a full 2 in. open stroke length. In 2009, the distributed control system (DCS) was installed utilizing these drawings and was setup under the assumption that both valves, LCV-9005 and LCV-9006, were the same model valves and stroke lengths.The DCS system was designed to provide a signal to throttle the feedwater bypass valves following a reactor trip to 20 percent open to provide approximately 5 percent feed flow in order to recover steam generator water levels utilizing main feedwater. During Unit 2 startup activities in November 2013, the licensee noted a discrepancy in the valve positions for LCV-9006 and LCV-9005 when they were providing steam generator water level control. The licensee placed the issue in the corrective action program under Action Request (AR) 1921720 and determined that it was necessary to evaluate a revision of the LCV-9005 DCS setpoint, which was accomplished by an engineering condition evaluation under AR 1925428. The engineering condition evaluation was inadequate in that it failed to recognize the differences in the two different model valves, and therefore failed to provide adequate corrective actions to address performance issues associated with these differences.The final recommendation from AR 1925428 was that the current LCV-9005 setting did not impose any risk to the plant operation, as the 2A steam generator level had been within acceptable range with no control room alarm observed. Therefore, no setpoint change was required at that point.On October 26, 2017, following a Unit 2 trip, LCV-9005 was sent a digital DCS demand signal to be 20 percent open. Since the valve was locally set to have a maximum stroke of 1.5 in. instead of 2 in. open, the actual flow through the valve was less than 5 percent. This resulted in flow lower than needed to maintain 2A steam generator level, and caused level to lower, which eventually resulted in an actuation of the A train auxiliary feedwater actuation system (AFAS). Corrective Action(s):The licensee implemented corrective actions to: 1) properly set up LCV-9005 in order for it to have a full stroke length of 2 inches so that it could provide the required feedwater flow and, 2) update associated drawings to include correct stroke lengths.Corrective Action Reference(s): This issue was entered into the licensees CAP as AR 2232869
05000335/FIN-2017004-012017Q4Saint LucieInadequate Reactor System Trip Process for Inoperable Channel Results in Operation in a Condition Prohibited by Technical SpecificationsA Green, self-revealing NCV of 10 Code of Federal Regulations (CFR) Part 50, Appendix B, Criterion V, Instructions, Procedures and Drawings, was identified for the licensees failure to have an adequate procedure for reducing the trip setpoint of the B channel of the reactor protection system (RPS) high startup rate (HSUR) bistable. The licensees failure to establish an adequate procedure, as required by 10 CFR Part 50, Appendix B, Criterion V, Instructions, Procedures, and Drawings, to place the "B" channel wide range nuclear instrument in a tripped condition was a performance deficiency (PD). This deficiency resulted in a violation of Technical Specification (TS) Limiting Condition for Operation (LCO) 3.3.1.1. Following discovery of the condition, the licensee initiated immediate corrective actions to place the B channel RPS HSUR in trip, meeting the TS requirement. The inspectors determined that the finding was more than minor because it was associated with the Mitigating Systems cornerstone attribute of procedural quality and adversely affected the cornerstone objective of ensuring the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences (i.e., core damage). Specifically, there was no procedure to perform the setpoint reduction method as identified in 1-AOP-99.01. The only direction was to Contact I&C in the step. The Instrumentation and Control (I&C) processes used to implement the HSUR reduced setpoint reduction method were inadequate, in that, they did not evaluate all potential failure conditions when setting the HSUR bistable. The finding did not screen as greater than Green because while the degradation affected a single RPS trip signal, it did not affect the function of other redundant trips; and the finding did not involve control manipulations that unintentionally added positive reactivity; and finally the finding did not result in a mismanagement of reactivity by operators. Using IMC 0310, Aspects Within the Cross-Cutting Areas, the inspectors determined that the finding had a cross-cutting aspect in the area of human performance. Specifically, the cross- cutting aspect of resources (H.1) was assigned to the finding because the licensee did not ensure an adequate procedure was available to implement the HSUR setpoint reduction.
05000389/FIN-2017004-022017Q4Saint LucieFailure to Follow Surveillance Maintenance Procedure Resulting in a Condition Prohibited by Technical SpecificationsA Green, self-revealing, NCV of TS 6.8.1 was identified for the licensees failure to adequately implement a maintenance procedure during a monthly flow channel check for the 2C Auxiliary Feedwater (AFW) pump. Specifically, the licensee failed to implement as-written surveillance maintenance procedure 2-SMI-09.05C, 2C Auxiliary Feedwater Pump Flow Channel Check, when performing the channel checks for both 2C AFW pump flow transmitters. The licensees failure to follow surveillance maintenance procedure 2-SMI-09.05C, was a PD. Upon discovery, the flow transmitters were declared inoperable and subsequently, the condition was promptly restored to normal. The PD was more than minor because it was associated with the Human Performance attribute of the Mitigating Systems cornerstone and it adversely affected the cornerstone objective of ensuring the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences. The PD adversely affected the licensees ability to monitor 2C AFW flow during a design basis accident. The inspectors determined that the finding was not greater than Green because it did not represent a deficiency affecting the design or qualification of a mitigating system; it did not represent a loss of system and/or function; it did not represent an actual loss of function for at least a single train for more than its TS allowed outage time; and it did not represent an actual loss of function of one or more non-TS trains of equipment designated as high safety-significant in accordance with the licensees maintenance rule program. The finding involved the cross-cutting area of human performance, with an aspect of avoiding complacency (H.12), in that, the licensee failed to ensure that personnel effectively used human performance tools during the AFW pump flow channel check to ensure procedure steps were completed as required.
05000335/FIN-2017004-032017Q4Saint LucieFailure to Identify and Correct a Condition Adverse to QualityThe NRC-identified a Green non-cited violation (NCV) of 10 CFR Part 50, Appendix B, Criterion XVI, Corrective Actions, for failure to identify and correct a condition adverse to quality. The licensee failed to identify that their procedures lacked actions to install control power jumpers that are required to defeat the reactor coolant systems (RCS) pressure interlocks for the shutdown cooling (SDC) suction line motor operated valves (MOVs) when aligning the plant for hot leg injection (HLI) and then correct the condition. Following the identification of this procedural vulnerability, the licensee fabricated control power jumpers and revised procedure 1-GME-100.03, Installation and Removal of Temporary Power Jumpers for MOV V3481, V3652, V3432 AND V3444, to provide direction for installation of power jumpers. In addition, the licensee performed a more detailed failure modes and effects analysis to ensure that the revised procedures accounted for all possible single failures. This issue has been entered into the licensees corrective action program (CAP) as CR 2217631.The PD was more than minor because it was associated with the Design Control attribute of the Mitigating System cornerstone objective of ensuring the capability of the low pressure safety injection (LPSI) system to perform its required long term cooling safety function (HLI). The condition was evaluated by a Regional Senior Reactor Analyst and determined to have very low safety significance (Green) based on the low likelihood of a loss of coolant accident (LOCA) and low likelihood of electrical failures requiring jumpers to be installed. This issue and corrective actions were documented in the licensees CAP as Action Request (AR) 2217631. This finding was not assigned a cross-cutting aspect because the underlying cause was a legacy issue and not indicative of current performance.
05000335/FIN-2017002-012017Q2Saint LucieReactor Coolant Pressure Boundary Leak on the 1B2 Reactor Coolant Pump Lower Seal Heat ExchangerOn January 31, 2017, Unit 1 was shutdown to investigate and repair the source of RCS leakage in the vicinity of the 1B2 RCP seal package. The unidentified leakage rate measured was 0.17 gallons per minute (gpm), which is well below the TS limit of 1 gpm of unidentified leakage. Typical RCS unidentified leak rates are in the range of 0.05 - 0.07 gpm. The licensees investigation revealed the source of the leakage as RCS pressure boundary leakage from the RCP lower seal cooler. St. Lucie Unit 1 TS 3.4.6.2, Reactor Coolant System Operational Leakage, Action a was entered and the unit was placed in cold shutdown (Mode 5, less than 200 degrees F) in accordance with the TS. The 1B2 RCP rotating assembly and pump cover with the integral lower seal heat exchanger were replaced during the fall refueling outage which occurred between September 26 and November 8, of 2016. The RCP integral lower seal heat exchanger was a tube-in-tube heat exchanger that was permanently attached to the pump cover. The inner tube contained high pressure RCS water and the outer tube contained low pressure CCW. The heat exchanger was connected to the CCW supply and return piping utilizing flanges with the flange nuts torqued to 225-230 foot-pounds (ft-lbs,) as specified by the manufacturer. The manufacturer specified a change in the torque requirements in 2015 from a previous value of 125 ft-lbs when it was identified that the 125 ft-lbs specification was not the proper torque value for the size of the flange used. The leakage emanated from a crack in the inner tube material near the toe of a weld where the inner tube exits from the outer tube. The location was in the vicinity of a CCW system connection flange. Based on a review of containment atmospheric particulate monitor data and reactor cavity leakage flow instrument data, the licensee determined that the RCS pressure boundary leak started on November 9, 2016 or shortly thereafter. This was approximately one week after the RCP was started near the conclusion of the refueling outage.The licensee determined that the most probable cause of the cracked seal cooler tubing was due to a deficiency in the lower seal heat exchanger design that allowed stresses to approach or exceed the yield strength of the tubing when the flanges were torqued to connect the CCW piping to the cooler. The resultant plastic deformation of the tubing and associated flaw formation allowed low stress; high cycle fatigue from normal RCP operation, to propagate the flaw until it was through-wall, causing the pressure boundary leakage. A finite element analysis model, developed by an outside engineering firm for the RCP seal cooler, was used to support this conclusion. The finite element analysis model determined that when the CCW flange connection was torqued to 230 ft-lbs, a tensile stress was imparted that approached or exceeded the minimum yield strength of the lower seal heat exchanger tubing and possibly caused plastic deformation and subsequently an outside diameter surface flaw in the failure region. A counter torque could not reasonably be applied during installation due to the design of the CCW flange connection.This issue was documented in the licensees corrective action program as AR 2182938. Licensee corrective actions included; 1) removing the 1B2 RCP seal cooler heat exchanger flaw and completing a weld repair of the heat exchanger outlet tubing; 2) visually inspecting all Unit 1 and Unit 2 RCP lower seal heat exchangers to identify any leakage and the presence of any outer diameter surface flaws, and; 3) determining whether a lower torque value can be used when connecting CCW to the seal cooler heat exchanger, or by implementing a different method of torqueing the CCW flanges that would reduce the stress on the tubing to an acceptable level. Enforcement: St. Lucie Unit 1 TS limiting condition for operation 3.4.6.2, Reactor Coolant System Operational Leakage, required, in part, that RCS operational leakage shall be limited to no pressure boundary leakage during plant operations in Mode 1 through 4. With any pressure boundary leakage, Unit 1 had to be placed in hot standby (Mode 3) within 6 hours, and in cold shutdown (Mode 5) within the following 30 hours. Contrary to the above, Unit 1 experienced RCS pressure boundary leakage from approximately November 9, 2016, until the unit was shut down on January 31, 2017, and later cooled down to Mode 5 on February 1, 2017. The inspectors utilized the enforcement policy examples of Section 6.1, and available ris k- informed tools to assess the safety significance of the RCS pressure boundary leakage and related violation. Based on the fact that the through-wall crack leak rate was stable, was within the capacity of the charging system, and would not impact other systems used to mitigate a loss of coolant accident, the inspectors concluded the safety significance of the violation was very low and consistent with Severity Level IV. Additionally, the risk aspects were discussed and confirmed with a regional Senior Risk Analyst. This issue was documented in the licensees corrective action program as AR 2182938.The NRC exercised enforcement discretion in Enforcement Action (EA)-2017-117, in accordance with Section 3.10 of the Enforcement Policy because the violation was not associated with a licensee performance deficiency. Specifically, the violation was not attributable to an equipment failure that was avoidable by reasonable licensee quality assurance measures or management controls and therefore inspectors concluded that there was no performance deficiency associated with the RCS boundary leakage. The RCP cover with its integrated lower seal cooler was replaced with a new component and installed in accordance with vendor instructions. This enforcement discretion will not be considered in the assessment process or the NRCs Action Matrix. This LER is closed.
05000335/FIN-2017001-012017Q1Saint LucieInadequate Procedure Results in Adding an Incorrect Lubrication Oil to the 1B CS Motor Inboard BearingAn NRC-identified Green, non-cited violation (NCV) of Technical Specification (TS) 6.8.1, Procedures and Programs, was identified for the licensees failure to establish, implement, and maintain written procedures covering activities referenced in NRC Regulatory Guide 1.33, Revision 2, dated February 1978. Specifically, the licensees failure to maintain a plant lubrication manual with correct lubrication oil specifications for the 1B containment spray (CS) pump motor resulted in adding unacceptably low viscosity lubrication oil to the inboard bearing of the 1B CS pump motor. Immediate corrective actions included restoring the 1B CS pump inboard bearing with the correct lubrication oil and placing the issue in the licensees corrective action program.The licensees failure to correctly specify the 1B CS pump motor inboard bearing lubrication requirements in licensee general maintenance procedure GMP-22 was a performance deficiency (PD). The PD was more than minor because it was associated with the procedure quality attribute of the mitigating systems cornerstone and adversely affected the cornerstone objective to ensure the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences (i.e., core damage). Specifically, the inadequate procedure resulted in adding the incorrect lubrication oil to the 1B CS pump motor bearing, causing the pump to be declared inoperable for approximately 56.5 hours. The finding screened to Green because the failure did not: (1) affect the design or qualification of the systems, structures and components, (2) represent an actual loss of function, and (3) represent an actual loss of function of at least a single train for greater than its TS allowed outage time. The finding involved the cross-cutting area of human performance, in the aspect of avoid complacency, in that, the individuals involved with the procedure revision did not implement appropriate error reduction tools to ensure the procedure was appropriately changed to reflect the new lubrication oil requirement (H.12).
05000335/FIN-2016003-012016Q3Saint LucieReactor Coolant System Leakage Technical Specification ViolationAn NRC-identified Green non-cited violation (NCV) of Unit 1 Technical Specification 3.4.6.2 Reactor Coolant System Leakage was identified. Specifically, the licensee failed to enter TS 3.4.6.2 Action c for reactor coolant system pressure isolation valve (V3217) when the valve experienced operational seat leakage of approximately 30 gpm during flushing and cooling the shutdown cooling system. Immediate corrective actions were not required since the valve was later determined to be inoperable and repaired. The licensee entered this issue into the licensees corrective action program. The licensees failure to recognize that gross seat leakage from check valve V3217 indicated of a major problem with valve seat alignment and that higher differential pressure would not help seat the valve was a performance deficiency (PD). The performance deficiency is more than minor because it is associated with the barrier integrity cornerstone attribute of human performance and adversely affected the cornerstone objective of providing reasonable assurance that physical barriers such as the containment, protected the public from radionuclide releases caused by accidents or events. The PD resulted in 46 additional hours of operation with V3217 seat leakage outside of TS acceptance criteria which required the unit to be in cold shutdown. The finding involved the cross-cutting area of human performance and specifically within that area was associated with conservative bias because the operability evaluation did not demonstrate it was safe to proceed with valve V3217 experiencing gross seat leakage (H.14).
05000335/FIN-2016003-022016Q3Saint LucieLicensee-Identified ViolationLicensee identified violation (LIV) - T.S.6.8.1 requires written procedures be established, implemented, and maintained covering applicable procedures recommended in Appendix A of Regulatory Guide 1.33, Rev 2, 1978. Appendix A, Section 9, Procedures for Performing Maintenance, states, in part, that maintenance that can affect the performance of safety-related equipment should be properly preplanned and performed in accordance with written procedures, documented instructions, or drawings appropriate to the circumstances. Contrary to this, Unit 1 Pressure Isolation Valve (PIV) V3217 was rebuilt in October 2013, using Licensee procedure 0-GMM-80.22, Swing Check Valve Inspections. 0-GMM-80.22 did not provide specific detail to ensure consistency and first time work quality and directly resulted in V3217 being reassembled incorrectly. Specifically the disc arm bushings were installed backwards, as well as no spacers in the bushing bores. The period of concern was from the achievement of Mode 4 on August 5, 2016 at 09:43 hours, to declaration of entry into the TS action statement and entry into Mode 5 on August 4, 2016 at 20:03 hours, resulting in 82 hours of operation with V3217 seat leakage outside of TS acceptance criteria. The inspectors characterized the safety significance of the issue utilizing Manual Chapter 0609.04, Significance Determination Process Initial Characterization of Findings, and determined the issue affected the barriers cornerstone due to leakage past an isolation valve. Manual Chapter 0609 Appendix A, The significance determination process (SDP) for Findings At-Power, Exhibit 3 was used to further evaluate this finding which screened as Green because the finding represented neither an actual open pathway in the physical integrity of the reactor containment and does not involve an actual reduction in the function of the hydrogen igniters in the reactor containment. This issue has been entered into the licensees CAP as AR 2148252.
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