IR 05000259/2022011

Design Basis Assurance Inspection (Programs) Inspection Report 05000259/2022011 and 05000260/2022011 and 05000296/2022011

ML22258A132
Person / Time
Site:	Browns Ferry
Issue date:	09/16/2022
From:	James Baptist Division of Reactor Safety II
To:	Jim Barstow Tennessee Valley Authority
References
IR 2022011
Download: ML22258A132 (24)

Text

SUBJECT:

BROWNS FERRY NUCLEAR PLANT - DESIGN BASIS ASSURANCE INSPECTION (PROGRAMS) INSPECTION REPORT 05000259/2022011 AND 05000260/2022011 AND 05000296/2022011

Dear Mr. Barstow:

On August 5, 2022, the U.S. Nuclear Regulatory Commission (NRC) completed an inspection at Browns Ferry Nuclear Plant. On September 1, 2022, the NRC inspectors discussed the results of this inspection with Quinn Leonard and other members of your staff. The results of this inspection are documented in the enclosed report.

Two findings of very low safety significance (Green) are documented in this report. Two of these findings involved violations of NRC requirements one was determined to be Severity Level IV.

We are treating these violations as non-cited violations (NCVs) consistent with Section 2.3.2 of the Enforcement Policy.

A licensee-identified violation which was determined to be of very low safety significance is documented in this report. We are treating this violation as a non-cited violation (NCV)

consistent with Section 2.3.2 of the Enforcement Policy.

If you contest the violations or the significance or severity of the violations documented in this inspection report, you should provide a response within 30 days of the date of this inspection report, with the basis for your denial, to the U.S. Nuclear Regulatory Commission, ATTN:

Document Control Desk, Washington, DC 20555-0001; with copies to the Regional Administrator, Region II; the Director, Office of Enforcement; and the NRC Resident Inspector at Browns Ferry Nuclear Plant.

If you disagree with a cross-cutting aspect assignment in this report, you should provide a response within 30 days of the date of this inspection report, with the basis for your disagreement, to the U.S. Nuclear Regulatory Commission, ATTN: Document Control Desk, Washington, DC 20555-0001; with copies to the Regional Administrator, Region II; and the NRC Resident Inspector at Browns Ferry Nuclear Plant.September 16, 2022 This letter, its enclosure, and your response (if any) will be made available for public inspection and copying at http://www.nrc.gov/reading-rm/adams.html and at the NRC Public Document Room in accordance with Title 10 of the Code of Federal Regulations 2.390, Public Inspections, Exemptions, Requests for Withholding.

Sincerely, James B. Baptist, Chief Engineering Branch 1 Division of Reactor Safety Docket Nos. 05000259 and 05000260 and 05000296 License Nos. DPR-33 and DPR-52 and DPR-68

Enclosure:

As stated

Inspection Report

Docket Numbers: 05000259, 05000260 and 05000296

License Numbers: DPR-33, DPR-52 and DPR-68

Report Numbers: 05000259/2022011, 05000260/2022011 and 05000296/2022011

Licensee: Tennessee Valley Authority

Facility: Browns Ferry Nuclear Plant

Location: Athens, Alabama

Inspection Dates: July 18, 2022, to August 05, 2022

Inspectors: G. Ottenberg, Senior Reactor Inspector A. Ruh, Senior Reactor Inspector R. Waters, Contractor

Approved By: James B. Baptist, Chief Engineering Branch 1 Division of Reactor Safety

Enclosure

SUMMARY

The U.S. Nuclear Regulatory Commission (NRC) continued monitoring the licensees performance by conducting a design basis assurance inspection (programs) inspection at Browns Ferry Nuclear Plant, in accordance with the Reactor Oversight Process. The Reactor Oversight Process is the NRCs program for overseeing the safe operation of commercial nuclear power reactors. Refer to https://www.nrc.gov/reactors/operating/oversight.html for more information. A licensee-identified non-cited violation is documented in report section:

71111.21N.0

List of Findings and Violations

Failure to Promptly Identify Condition Adverse to Quality Associated with Unit 1 HPCI Steam Line Inboard Isolation Valve Cornerstone Significance Cross-Cutting Report Aspect Section Mitigating Green [H.12] - Avoid 71111.21N.

Systems NCV 05000259/2022011-01 Complacency 02 Open/Closed The inspectors identified a Green finding and associated Non-cited Violation (NCV) of 10 CFR 50, Appendix B, Criterion XVI when the licensee failed to promptly identify a condition adverse to quality associated with the potential to damage the Unit 1 high pressure coolant injection (HPCI) steam line inboard isolation valve.

Failure to Ensure Change to MSIVs Could be Implemented Without Requesting a License Amendment Cornerstone Significance/Severity Cross-Cutting Report Aspect Section Barrier Integrity Green None (NPP) 71111.21N.

Severity Level IV 02 NCV 05000259,05000260,05000296/202201 1-02 Open/Closed The inspectors identified a Green finding and associated Severity Level IV NCV of 10 CFR 50.59(c)(1)(i) when the licensee failed to obtain a license amendment to change the technical specifications (TS) prior to making a change to the facility regarding establishment of a minimum required main steam isolation valve (MSIV) accumulator pressure.

Additional Tracking Items

None.

INSPECTION SCOPES

Inspections were conducted using the appropriate portions of the inspection procedures (IPs) in effect at the beginning of the inspection unless otherwise noted. Currently approved IPs with their attached revision histories are located on the public website at http://www.nrc.gov/reading-rm/doc-collections/insp-manual/inspection-procedure/index.html. Samples were declared complete when the IP requirements most appropriate to the inspection activity were met consistent with Inspection Manual Chapter (IMC) 2515, Light-Water Reactor Inspection Program - Operations Phase. The inspectors reviewed selected procedures and records, observed activities, and interviewed personnel to assess licensee performance and compliance with Commission rules and regulations, license conditions, site procedures, and standards.

REACTOR SAFETY

71111.21N.02 - Design-Basis Capability of Power-Operated Valves Under 10 CFR 50.55a Requirements POV Review (IP Section 03)

The inspectors:

a. Determined whether the sampled POVs are being tested and maintained in accordance with NRC regulations along with the licensees commitments and/or licensing bases.

Specific Guidance b. Determined whether the sampled POVs are capable of performing their design-basis functions.

c. Determined whether testing of the sampled POVs is adequate to demonstrate the capability of the POVs to perform their safety functions under design-basis conditions.

d. Evaluate maintenance activities including a walkdown of the sampled POVs (if accessible).

(1) 1-FCV-74-52, Residual Heat Removal (RHR) System 1 Low Pressure Coolant Injection Outboard Injection Valve

(2) 1-FCV-73-2, High Pressure Coolant Injection Steam Line Inboard Isolation Valve

(3) 2-FCV-23-52, RHR Heat Exchanger 2D RHR Service Water Outlet Valve

(4) 2-FCV-74-57, RHR System 1 Suppression Chamber/Pool Isolation Valve

(5) 2-FCV-71-2, Reactor Core Isolation Cooling Steam Line Inboard Isolation Valve

(6) 1-FCV-85-37E, East Control Rod Drive Scram Discharge Volume Drain Control Valve

(7) 2-FCV-1-37, Main Steam Line C Inboard Isolation Valve

(8) 3-FCV-63-8A, Standby Liquid Control Squib Valve

INSPECTION RESULTS

Failure to Promptly Identify Condition Adverse to Quality Associated with Unit 1 HPCI Steam Line Inboard Isolation Valve Cornerstone Significance Cross-Cutting Report Aspect Section Mitigating Green [H.12] - Avoid 71111.21N.0 Systems NCV 05000259/2022011-01 Complacency 2 Open/Closed The inspectors identified a Green finding and associated Non-cited Violation (NCV) of 10 CFR 50, Appendix B, Criterion XVI when the licensee failed to promptly identify a condition adverse to quality associated with the potential to damage the Unit 1 high pressure coolant injection (HPCI) steam line inboard isolation valve.

Description:

In 2016, the Unit 1 HPCI steam line inboard isolation valve 1-FCV-73-2 experienced a valve stem failure and loss of valve and system function. The cause of the failure was related to the valve and actuator design which resulted in the valve coasting into its backseat when stroked at normal operating pressures. A high motor inertia after open limit switch trip coupled with high stem rejection loads resulted in backseating during routine quarterly stroke time testing and after system maintenance outages. Small misalignments between the stem and backseat surface induced high bending stress in the stem and subsequent failure. Engineering evaluations of the condition underestimated the possible stem stresses which led to acceptance of the practice of uncontrolled backseating of the valve. The failure to promptly identify deficiencies in these evaluations was the subject of NCV 05000259/2016003-04, Inadequate Prompt Determination of Operability for HPCI Steam Line Inboard Isolation Valve. As corrective action for the failure, design changes were implemented on the three units which involved changing the stem thread geometry to reduce stem and disc travel speeds by extending the overall stroke time from 12.78 seconds to 19.15 seconds and adding more resistance to stem travel by increasing the target packing load.

In March 2019 effectiveness review actions on Unit 2 involved stroking the valve with normal operating pressure present as the unit was being shutdown for a refueling outage to demonstrate adequacy of the modified design. The result of this test found the valve was on its backseat and that the lower packing end ring had lost its integrity causing a 74% loss in frictional running loads. This loss of frictional load may have been related to specifying torques near the strength limit of the packing which did not account for fastener lubrication. An internal valve inspection was performed, and no damage was identified on the valve stem or bonnet. A stronger set of packing with enhanced consolidation practices were implemented prior to Unit 2 startup. CR 1499686 was initiated to evaluate the potential for future failures to occur on the other units due to incorrect design or effective setup. The operability determination concluded that if the Unit 1 or 3 valves were stroked under pressure due to a HPCI isolation and subsequent re-opening of the valves, they would most likely not backseat. However, even if they did backseat, no damage to the valves would be expected, and they would continue to be able to perform their design basis functions. This assessment was based on the lack of damage to the Unit 2 valve and the open limit switch setting on Units 1 and 3 being set at 3% and 4% further away from the backseat than the Unit 2 valve. This difference meant the Unit 1 and 3 valves would have slightly more time to coast down compared to Unit 2. Additionally, the respective packing nut torques applied on Units 1 and 3 were 17% and 6% lower than on Unit 2 and engineers did not expect their packing would be over-stressed.

In February 2020 the same effectiveness review actions were accomplished on Unit 3 during reactor shutdown for a refueling outage. The valve was also found to be in its backseat and frictional running loads had degraded 78% over the operating cycle. While the Unit 3 valve was backseated, diagnostic equipment was connected to the valve stem which revealed the stem was at approximately 90% of its yield strength. An internal valve inspection was performed because of anomalous readings during a diagnostic test, but no damage was identified on the valve stem or bonnet. In May 2020 engineers concluded that the results from the Unit 2 and 3 backseating events were sufficient to determine that the design changes implemented as corrective actions to prevent recurrence were not effective.

Earlier, in July 2019, the Unit 1 HPCI steam line inboard isolation valve was automatically closed due to an inadvertent HPCI isolation caused by an error during unrelated electrical maintenance. The valve was reopened approximately 4.5 hours5.787037e-5 days <br />0.00139 hours <br />8.267196e-6 weeks <br />1.9025e-6 months <br /> later to restore the system to an operable status. No condition reports were written to identify that the Unit 1 valve may have been backseated. In the May 2020 effectiveness review, engineers stated it was expected that the Unit 1 valve would be found in the backseat during the October 2020 refueling outage because the valve was opened at power in July 2019 as part of recovery from the steam line isolation and based on their experience with the Unit 2 and 3 valves. Engineers still expected the valve to be in a satisfactory condition based on the March 2019 operability determination and internal inspections on Unit 2 and 3. A work order was already planned to investigate if the valve was on its backseat, but it was eventually cancelled because the valve configuration was disturbed during the unit shutdown which precluded the opportunity to confirm whether it was backseated or not.

Inspectors identified that the October 2020 as-found cold shutdown stroke times indicated the valves were starting their close stroke from an approximately 98% open position, whereas the as-left condition from the 2018 outage indicated the valve was starting from a 90% open position. This implied the valve had lost a substantial amount of running frictional loads and that the valve was nearly hitting the backseat even with no steam pressure contributing a stem rejection load. Since the stroke times satisfied the test acceptance criteria and no other intrusive outage work was planned on the valve, the valve was not repacked with the improved packing design and no internal inspection was performed to assess the potential damage from the July 2019 backseating event.

Inspectors were concerned that the current valve condition rendered the valve stem vulnerable to failure if it was backseated again in the future. The previous evaluation in CR 1499686 failed to consider certain effects and the evaluation was not updated as contrary information became available. First, the evaluation did not consider the impacts of thermal stress which had been previously identified as a significant effect in a previous NRC inspection report, the vendor manual, and the licensees 2016 root cause analysis. Thermal stress can develop if the valve stem is allowed to heat up inside the valve while in a closed position for an extended duration and then brought directly to the backseat without allowing the withdrawn portion of the stem to cooldown first. Because the July 2019 event had the valve closed for 4.5 hours5.787037e-5 days <br />0.00139 hours <br />8.267196e-6 weeks <br />1.9025e-6 months <br />, backseating the valve would have induced thermal stress that was not present during the Unit 2 and 3 effectiveness review actions since those actions involved valve closure followed by an immediate open stroke with only seconds of dwell time. Secondly, comparative assessments between the units during static diagnostic tests indicated that the Unit 1 motor had higher inertia than the other units. This was indicated by the need to set the open limit switch further from the backseat to achieve the same after-coast valve position and was also reflected in the closing stroke inertial load after torque switch trip. Thirdly, the loss of packing load indicated by cold shutdown stroke time testing was not considered. Based on plant operating experience, the same circumstances that were present prior to the Unit 1 2016 stem failure were established. Namely, a degraded packing load existed, and the valve was subjected to backseating and thermal stresses during its previous open stroke. If these combined effects deform the stems backseat surface, high bending stresses can be induced during subsequent backseating events resulting in fracture. Stem failure would cause a loss of redundancy in the capability to isolate a HPCI steam line break.

The potential for damage to the Unit 1 valve represented a condition adverse to quality as defined by station procedure NPG-SPP-22.300, Corrective Action Program. The station failed to promptly identify this condition until inspectors raised questions about the valves condition and adequacy of the evaluations. Additionally, general engineering specification G-50, Torque, Thrust and Control Switch Settings for Motor-Operated Valves, similarly required engineers to initiate a CR and perform an engineering evaluation when a valve is found to have traveled into the backseat. Although engineers expected the Unit 1 valve was backseated, no CR or evaluation was created.

Despite the vulnerability, changes to the inservice testing program were made following the 2016 failure so that the valve no longer needed to be cycled quarterly at power. Because of this, the valve is normally left open during the entire operating cycle and only opened before steam line pressures reach normal operating pressure. For planned system outages, the valve is normally left open and the redundant valve is used for isolation. Although the valve was vulnerable to failure, there were no design basis events that required the valve to be able to close and subsequently reopen for event mitigation. Since the 2020 refueling outage, the valve has remained open with capability to close as designed.

Corrective Actions: The licensee entered the issue into the corrective action program, initiated work orders to diagnostically test the valve during the November 2022 refueling outage to determine the remaining packing load to support evaluation of potential past backseating forces and need for internal inspection. Operations evaluated the condition for establishment of an operator work around to ensure an evaluation would be performed if it became necessary to open the valve at power.

Corrective Action References: 1793962, 1793344

Performance Assessment:

Performance Deficiency: The failure to identify and evaluate the effects of backseating 1-FCV-73-2 on July 12, 2019 as required by station general engineering specification G-50, Torque, Thrust and Control Switch Settings for Motor-Operated Valves, was a performance deficiency. Specifically, section 2.3 required a CR to be initiated and an engineering evaluation performed, but neither were accomplished.

Screening: The inspectors determined the performance deficiency was more than minor because if left uncorrected, it would have the potential to lead to a more significant safety concern. Specifically, plant operating experience demonstrated the valve stem can fracture once backseated after undergoing the conditions created on the July 2019 valve stroke.

Significance: The inspectors assessed the significance of the finding using IMC 0609 Appendix A, The Significance Determination Process (SDP) for Findings At-Power. Using Exhibit 2 "Mitigating Systems Screening Questions," inspectors determined the issue was Green because the deficiency affected the design or qualification of the valve, but because the valve had not been opened with full operating pressure present after the July 2019 event, it maintained its operability.

Cross-Cutting Aspect: H.12 - Avoid Complacency: Individuals recognize and plan for the possibility of mistakes, latent issues, and inherent risk, even while expecting successful outcomes. Individuals implement appropriate error reduction tools. In this case, engineers relied on prior evaluations based on successful outcomes for unit 2 and 3 valves, but those evaluations did not account for more severe conditions created on unit 1. Additionally, engineers did not seek to validate past assumptions as new information became available or take proactive measures to schedule prudent maintenance during the 2020 refueling outage.

Enforcement:

Violation: 10 CFR 50, App. B, Criterion XVI "Corrective Action" requires, in part, that Measures shall be established to assure that conditions adverse to quality, such as failures, malfunctions, deficiencies, deviations, defective material and equipment, and nonconformances are promptly identified and corrected. Site procedure NPG-SPP-22.300, section 5.0, defined these conditions as including those that could result in damage to plant equipment. Contrary to the above, since July 12, 2019, the site failed to promptly identify a condition adverse to quality. Specifically, that the 1-FCV-73-2 valve stem had been subjected to backseating forces and thermal stresses after opening the valve with normal system pressure conditions and that subsequent stroking could result in damage to plant equipment based on plant operating experience.

Enforcement Action: This violation is being treated as a non-cited violation, consistent with Section 2.3.2 of the Enforcement Policy.

Failure to Ensure Change to MSIVs Could be Implemented Without Requesting a License Amendment Cornerstone Significance/Severity Cross-Cutting Report Aspect Section Barrier Green None (NPP) 71111.21N.0 Integrity Severity Level IV 2 NCV 05000259,05000260,05000296/2022011-02 Open/Closed The inspectors identified a Green finding and associated Severity Level IV NCV of 10 CFR 50.59(c)(1)(i) when the licensee failed to obtain a license amendment to change the technical specifications (TS) prior to making a change to the facility regarding establishment of a minimum required main steam isolation valve (MSIV) accumulator pressure.

Description:

In 2015, during an air operated valve program review for the MSIVs, CR 1098857 described discovery that elevated containment pressure conditions following a LOCA would prevent the inboard MSIVs from closing during peak containment pressures using valve actuator springs alone. Additional force from gas pressure in the attached air accumulator was needed to ensure closure. Section 7.3.4.6 of the updated final safety analysis (UFSAR) previously described that the inboard MSIVs were designed to close under either pneumatic pressure or spring force with the vented side of the piston operator at the containment peak accident pressure. Also, that the outboard MSIV was exactly the same design, although it would be subjected only to atmospheric pressures. After recognizing the inadequacy of the valve springs to overcome elevated ambient pressures, the licensee submitted licensee event report (LER) 50-259/2015-005-00 describing periods where conditions prohibited by TS existed and that corrective actions were being developed to restore positive margin to the actuator capability for the inboard MSIVs. Engineers developed design change (DCN) 72226, Adjust Setpoints for 1/2/3-PS-32-70 to modify the licensing basis of the facility as permitted by 10 CFR 50.59 Changes, Tests, and Experiments.

DCN 72226 modified the closure time for the inboard MSIVs during a loss of coolant accident (LOCA) inside containment by crediting the reduction in core and containment pressures corresponding to two minutes following a LOCA rather than peak core and containment pressures. Calculation MDQ0000012016000566, MSIV Component Level Review, supported the DCN by evaluating the capability of the inboard and outboard MSIVs under various conditions. The conclusion of the calculation established acceptance criteria including minimum required setpoints for setup of the MSIVs. Based on an ambient containment pressure of 16.2 pounds per square inch gage (psig) and steam line pressure of 100 psig at two minutes during a LOCA inside containment, a minimum accumulator pressure of 90 psig was necessary for the inboard MSIVs to ensure closure within two minutes with 45.59%

margin. Based on a steam tunnel accident pressure of 6.94 psig and 1190 psig steam line pressure, a minimum accumulator pressure of 81 psig was necessary for the outboard MSIV to ensure closure with 9.51% margin. The DCN also changed the low pressure alarm setpoint of each units set of drywell control air receiver tanks to ensure adequate drywell control air pressure to close the inboard MSIVs.

The 10 CFR 50.59 evaluation for the DCN concluded that no change was required to the TS since the DCN did not affect the MSIV stroke time testing associated with TS 3.6.1.3, Primary Containment Isolation Valves, and that only a clarification was needed in the TS Bases regarding closure requirements during a LOCA. The TS Bases for LCO 3.6.1.3, previously described that the MSIVs are required to close within three to five seconds since a five second closure time was consistent with or conservative to the times assumed in the analyses in the UFSAR. Following implementation of the DCN, various sections of the UFSAR were modified to permit inboard MSIV closure times of up to two minutes during a LOCA. The two minute closure was seen as permissible because the facility was licensed for alternate source term per 10 CFR 50.67, which specified the onset of a radiological gap release from the fuel during a LOCA began at two minutes for boiling water reactors.

Inspectors noted that when valves similarly required gas pressure to perform their safety function, surveillance requirements were specified in the TS to verify adequate pressure for valve operation. For example, TS 3.5.1, ECCS - Operating included a TS surveillance (SR)3.5.1.3 to verify automatic depressurization system air supply header pressure is greater than or equal to 81 psig. Since the MSIVs were previously described in the UFSAR as being able to close against peak containment pressures using spring force alone, the plants control air systems were not technically required to support system operability. Following implementation of the DCN, operability of the inboard and outboard MSIVs depended on spring force in addition to a minimum accumulator pressure to ensure adequate actuator capability for closure during accident conditions. 10 CFR 50.59(c)(1)(i) required licensees evaluate whether a change to the TS is required prior to making changes to the facility. 10 CFR 50.36(c) established what items were necessary to include in TS, and 50.36(c)(3)included surveillance requirements, which are defined as, requirements relating to test, calibration, or inspection to assure that the LCO will be met. In this case, the licensee incorrectly concluded that a change to the TS was not required prior to implementing DCN 72226.

Corrective Actions: The licensee entered the issue into the corrective action program to develop plans for restoring compliance.

Corrective Action References: 1794387

Performance Assessment:

Performance Deficiency: The failure to obtain a license amendment to change the TS prior to making changes to the facility as required by 10 CFR 50.59(c)(1)(i) was a performance deficiency. Specifically, DCN 72226 modified the design and licensing basis for the inboard and outboard MSIVs by adding a minimum required accumulator pressure to ensure closure capability, but no TS surveillance requirements per 10 CFR 50.36(c) relating to test, calibration, or inspection of accumulator pressure, to assure that TS LCO 3.6.1.3 would be met, were proposed.

Screening: The inspectors determined the performance deficiency was more than minor because it was associated with the Design Control attribute of the Barrier Integrity cornerstone and adversely affected the cornerstone objective to provide reasonable assurance that physical design barriers protect the public from radionuclide releases caused by accidents or events. Specifically, the performance deficiency related to a plant modification made without incorporating TS SRs to provide reasonable assurance of the capability to maintain functionality of containment isolation.

Significance: The inspectors assessed the significance of the finding using IMC 0609 Appendix H, Containment Integrity SDP. Inspectors assessed the issue was a Type B finding since the performance deficiency was not expected to have a direct impact on the likelihood of core damage, but have potentially important implications for containment integrity. A phase 2 analysis was completed because findings at power affecting containment isolation valves are important to LERF for BWR Mark I containments. The risk significance was determined to be Green since the finding was associated with a regulatory process error and did not represent a physical degraded condition such as actual or potential leakage exceeding 10,000 standard cubic feet per hour through a MSIV for greater than 3 days. Inspectors also informed their determination by reviewing historical operator rounds and narrative log information to confirm the licensee was maintaining drywell control air pressures consistent with the minimums derived in site calculations.

Cross-Cutting Aspect: Not Present Performance. No cross-cutting aspect was assigned to this finding because the inspectors determined the finding did not reflect present licensee performance.

Enforcement:

The ROPs significance determination process does not specifically consider the regulatory process impact in its assessment of licensee performance. Therefore, it is necessary to address this violation which impedes the NRCs ability to regulate using traditional enforcement to adequately deter non-compliance.

Severity: Based on the examples provided in section 6.1 of the Enforcement Policy, dated January 14, 2022, "Reactor Operations," the performance deficiency was determined to be a SL IV violation. Specifically, example 6.1.d.2 states that a SL IV violation involves violations of 10 CFR 50.59 resulting in conditions evaluated as having a very low safety significance (i.e. green) by the significance determination process.

Violation: 10 CFR 50.59(c)(1)(i) requires, in part, that the licensee may make changes without obtaining a license amendment only if a change to the TS is not required. 10 CFR 50.36(c) established what items are necessary to include in TS, and 50.36(c)(3) included surveillance requirements, which are defined as, requirements relating to test, calibration, or inspection to assure that the LCO will be met. Contrary to the above, the station made changes to the facility without obtaining a license amendment for a change to the TS. Specifically, LCO 3.6.1.3 required that Each Primary Containment Isolation Valve, except reactor building-to-suppression chamber vacuum breakers, shall be operable, and DCN 72226 added a minimum required accumulator pressure to assure the MSIVs would be able to meet the LCO; however, no license amendment was submitted to change the TS surveillance requirements to add tests, calibrations, or inspections regarding accumulator pressure.

Enforcement Action: This violation is being treated as a non-cited violation, consistent with Section 2.3.2 of the Enforcement Policy.

Licensee-Identified Non-Cited Violation 71111.21N.02 This violation of very low safety significance was identified by the licensee and has been entered into the licensee corrective action program and is being treated as a non-cited violation, consistent with Section 2.3.2 of the Enforcement Policy.

Violation: 10 CFR 50, Appendix B, Criterion XVI "Corrective Action" requires, in part, that, in the case of significant conditions adverse to quality... measures shall assure that the cause of the condition is determined and corrective action taken to preclude repetition." Contrary to this, corrective actions taken per CR1193943 were ineffective to preclude repetition. Specifically, design changes were implemented as corrective actions to preclude repetition, but were inadequate to assure the valves would not be on the backseat following stroking of 1/2/3-FCV-73-2 (High Pressure Coolant Injection Steam Line Inboard Isolation)under system pressure conditions.

Significance/Severity: Green. Using IMC 0609, Appendix A, "The Significance Determination Process for Findings at Power," Exhibit 2, "Mitigating Systems Screening Questions," the inspectors determined the issue was Green because the deficiency affected the design or qualification of the valves, but they maintained their operability.

Corrective Action References:

EXIT MEETINGS AND DEBRIEFS

The inspectors verified no proprietary information was retained or documented in this report.

On September 1, 2022, the inspectors presented the design basis assurance inspection (programs) inspection results to Quinn Leonard and other members of the licensee staff.

On August 5, 2022, the inspectors presented the initial inspection results to Joseph Quinn and other members of the licensee staff.

DOCUMENTS REVIEWED

Inspection Type Designation Description or Title Revision or

Procedure Date

71111.21N.02 Calculations EDQ006320040020 Reactor Building Essential Mild Calculation for 4

Standby Liquid Control-System 063

EDQ2574920145 Degraded Voltage Analysis 3

EDQ2999880715 Thermal Overload Heater Calculation for MOVs 50

KEI Document No. System Level Review Calculation for Browns Ferry 0

3508C Main Steam Isolation Valves

KEI Document No. Component Level Review Calculation for Browns 0

3509C Ferry Main Steam Isolation Valves

MD00000232018000771 MOV 1/2/3-FCV-023-0034/-0040/-0046/-0052, 0

Operator Requirements and Capabilities

MDQ0000012016000566 MAIN STEAM ISOLATION VALVE (MSIV) 2

COMPONENT LEVEL REVIEW

MDQ0000232020000773 MOV Differential Pressure Calculation - RHR 0

Service Water System MOVS

MDQ0000742018000800 MOV 1/2/3-FCV-074-0052 & -0066, Operator 0

Requirements and Capabilities

MDQ0000742020000771 MOV Differential Pressure Calculation - Residual 1

Heat Removal (RHR) System MOVS

MDQ000074880225 Total RHR System Head Vs. Flow Rate 8

MDQ0001960036 MSIV Leakage Containment System Boundaries, 22

Physical Properties, System 001

MDQ0009992012000083 JOG MOV Periodic Verification Classification 26

MDQ0009992015000464 Scoping of Category 1 and 2 AOVs - BFN Units 1, 7

2, and 3

MDQ0032870288 Control Air Volume and Wall Thickness of 14

Accumulators

MDQ0063900083 STANDBY LIQUID CONTROL SYSTEM FLOW 9

ANALYSIS FOR ATWS REQUIREMENTS

MDQ007420020025 Residual Heat Removal System (RHR) Modes of 6

Operation

MDQ099920040034 Set Point Controls Parameters Review Calculation 18

for BFN Category 2 Air Operated Valves (AOVS)

Inspection Type Designation Description or Title Revision or

Procedure Date

MDQ0999980001 MOV Calculation Input Parameters 37

MDQ107320020058 MOV 1-FCV-073-0002, Operator Requirements and 6

Capabilities

MDQ2023910070 MOV 2-FCV-23-52, Operator Requirements and 14

Capabilities

MDQ2071910081 MOV 2-FCV-71-02, Operator Requirements And 8

Capabilities

MDQ2074910119 MOV 2-FCV-74-57 Operator Requirements and 14

Capabilities

MDQ3063910224 Standby Liquid Control System-Modes of Operation6

NDQ0000970008 LOCA ANALYSIS 13

NDQ0031920075 CONTROL ROOM AND OFFSITE DOSES DUE TO 31

A LOCA

NDQ006320040007 Total Integrated Radiation Dose to Selected 4

Standby Liquid Control System Components and

Cables

NDQ0074880118 Evaluation of LPCI Flow to Reactor Pressure Vessel 8

(RPV) with Failed Open Min-Flow Bypass Valve

Corrective 945325, 1786141,

Action 1711547, 1680519,

Documents 1678469, 1572492,

1714530, 1712533,

1711939, 1790852,

1444812, 1324216,

23619, 1756541,

1786141, 1711547,

1680519, 1678469,

1769257, 945325,

1746242, 1460491,

1061051, 1494872,

1499686, 1588781,

1609456, 1217802,

1061051, 1193943,

1494972, 1193943,

Inspection Type Designation Description or Title Revision or

Procedure Date

1448419, 1499589,

21253, 1656437,

1659001, 1676105,

1678571, 1680857,

1098857, 1271788,

28902, 1136776

Corrective 1711939 Engineering evaluation of worn bearing in the

Action intermediate gear train of 1-74-52 requested

Documents 1790688 Admin error for MSIV leakage admin limits in 0-TI-

Resulting from 360

Inspection 1790705 Improper stem material selected during diagnostic

test of 2-FCV-74-57

1790927 Clarify selected OAR is bounding for inertial loading

1790946 Admin error in U2 EOI Appendix-17C

1791182 Review SR-3.5.1.3 for pressure requirements

1791222 Admin error in references for ECI-0-000-MOV013

1792854 Additional guidance and clarification needed for Fail-

Safe testing methods per ISTC-3560

1793344 Perform MOV diagnostic testing on 1-FCV-73-2

during 1R14 to determine packing loads

1793447 Potential gaps with actions taken for ineffective

CAPR determination

1793874 Additional details needed in 0-TI-362(BASES) to

document MSIV stroke time acceptance criteria

bases

1793891 Review MSIV test procedures to determine if

additional information is needed

1793962 Evaluate the effect of potentially backseating 1-FCV-

73-2 during restoration in July 2019

1793970 UFSAR chapter 4.6 and limit switch settings relative

to IST stroke time acceptance criteria

1794042 MDQ0000012016000566 requires more detail

regarding basis for inputs made

1794269 Guidance for DWCA low pressure alarms does not

Inspection Type Designation Description or Title Revision or

Procedure Date

adequately advise operations of potential impacts to

inboard MSIV operability

1794279 Evaluate motor start limitation guidance and

cooldown periods for 1-MVOP-74-52

1794357 Review impacts of exceeding design pressure of

drywell control air system

1794382 Documentation for excluding squib valves from EQ

program could be enhanced

1794387 DCN 72226 did not identify that a change to the TS

for a new SR was required for minimum DWCA

pressure feeding MSIV accumulators

Drawings 0-A-12337-M-1E Pressure Seal Angle Valve with Limitorque SMB-5T 2

Operator

0-D-376495-2 Series SD Valve Assembly 1

0-VPF2486-25-2 Cast Steel Gate Valve with Limitorque SMB-2 4

Operator

1-47A367-74-52 Limit Switch Development and MOV Data 3

1-47E811-1 Flow Diagram Residual Heat Removal System 48

1-47E820-6 Flow Diagram Control Rod Drive Hydraulic System 6

1-47E820-7 Flow Diagram Control Rod Drive Hydraulic System 13

1-W0326086 10-900 Lb Double Disc Gate Valve Weld Ends, 2

Carbon Steel, Body Drain Pipe with Cap, Smart

Stem & Advanseal with Limitorque SMB-2-80

Actuator

1617-139 Trigger Assembly for 1" O.D.T.S Con-O-Cap A & C

21-186 Primer Chamber Assembly for 1" O.D.T.S. Con-O-C & E

Cap

1832-117 Valve Assembly Con-O-Cap Type, Explosive J

Actuated

2-47A367-23-52 Limit Switch Development and MOV Data 0

2-47E2847-1 Mechanical I & C Flow Diagram Control Air System 34

2-47E2847-10 Mechanical I & C Flow Diagram Control Air System 1

2-47E2847-2 Mechanical I & C Flow Diagram Control Air System 16

2-47E2847-3 Mechanical I & C Flow Diagram Control Air System 20

Inspection Type Designation Description or Title Revision or

Procedure Date

2-47E2847-4 Mechanical I & C Flow Diagram Control Air System 40

2-47E2847-5 Mechanical I & C Flow Diagram Control Air System 29

2-47E2847-6 Mechanical I & C Flow Diagram Control Air System 17

2-47E2847-7 Mechanical I & C Flow Diagram Control Air System 15

2-47E2847-8 Mechanical I & C Flow Diagram Control Air System 16

2-47E2847-9 Mechanical I & C Flow Diagram Control Air System 16

2-47E610-1-1 Mechanical Control Diagram Main Steam System 43

2-47E610-1-2 Mechanical Control Diagram Main Steam System 19

2-47E610-32-1 Mechanical Control Diagram Control Air System 12

2-47E610-32-2 Mechanical Control Diagram Control Air System 33

2-47E610-32-3 Mechanical Control Diagram Control Air System 20

2-47E801-1 Flow Diagram Main Steam 34

2-47E801-1-APPJ Appendix J Testing Boundary for Main Steam 12

System

2-47E811-1 Flow Diagram Residual Heat Removal System 77

2-47E858-1 Flow Diagram RHR Service Water System 36

2-730E927 Elementary Diagram Primary Cntmt Isln Sys 20

3-45E779-3 WIRING DIAGRAM 480V SHUTDOWN AUX 34

POWER SCHEMATIC DIAGRAM

3-47E225-119 Harsh Environmental Data El 639.0' 8

3-47E610-63-1 Mechanical Control Diagram Standby Liquid Control 9

System

3-47E854-1 Flow Diagram Standby Liquid Control System 14

75073-02 26" Main Steam Isolation Valve Cylinder Operated-6

Modification 23" Dia Seat Bore

SD-7900 2 - 900LB Type Y Globe Valve G

SD-7907 2 - 900LB Type Y Globe Valve F

VPDS 1-FCV-073-0002 Valve Packing Datasheet 4

VPDS 2-FCV-073-0002 Valve Packing Datasheet 5

VPDS 3-FCV-073-0002 Valve Packing Datasheet 7

VPDS 3-FCV-073-0002 Valve Packing Datasheet 8

Engineering BFN-18-033-1, 70293, Add Valves to the GL 89-10 and GL 96-05 Programs 0

Changes 72161, 72095, 69899,

Inspection Type Designation Description or Title Revision or

Procedure Date

69900, 70940

DCN 66314 Modify MSIV internal configurations as needed for A

EPU

DCN 72226 Adjust setpoints for 1/2/3-PS-32-70 A

Engineering 10.3.390 Copes Vulcan Seismic Analysis 12x16x12 Class 2

Evaluations 300 MOV

10.4.200 Copes Vulcan Weak Link Report 16 Class 300 3

MOV

21-1-IST-074-783 Evaluation of Test Results for the ASME OM Code 08/05/2021

IST Program

ANP-3546P Browns Ferry Units 1, 2, and 3 LOCA Break 0

Spectrum Analysis for ATRIUM 10XM Fuel (EPU

MELLLA+)

ANP-3873P ATRIUM 10XM Fuel Rod Thermal-Mechanical 0

Evaluation for Browns Ferry Unit 2 Cycle 22

EWR11MEB999080 Motor Starts for GL 89-10 Valves 03/12/2011

KEI 3055C Back-seating Stem Force Calculation for BFN-1- 0

FCV-73-0002

MDQ0009992015000464 Scoping of Category 1 and 2 Air Operated Valves-7

Browns Ferry Nuclear Plant Units 1, 2, & 3

MPR 0048-0067-CALC-Evaluation of 3-FCV-73-2 Stem Backseat Loading 0

001

NEDO-10320 THE GENERAL ELECTRIC PRESSURE April 1971

SUPPRESSION CONTAINMENT ANALYTICAL

MODEL

RAL-2634 Design, Seismic, and Weak-Link Analysis 2

SR-128 Crane Nuclear Seismic/Weak Link Report 5

SR-462 CNI Report, Seismic / Weak Link Report 3

TVAEBFN055-REPT-MSIV CLOSURE TIME STUDY TENNESSEE 0

001 VALLEY AUTHORITY BROWNS FERRY

NUCLEAR PLANT

WL-104 Crane Nuclear Weak Link Report 3

Miscellaneous ADAMS ML003691985 BROWNS FERRY NUCLEAR PLANT, UNITS 2 03/14/2000

AND 3 - ISSUANCE OF EXEMPTION FROM 10

Inspection Type Designation Description or Title Revision or

Procedure Date

CFR PART 50, APPENDIX J (TAC NOS. MA6815

AND MA6816)

ADAMS ML19354F589 General Electric Service Information Letter No. 477, 12/13/1988

"Main Steam Isolation Valve Closure"

ANF-89-98(P)(A) Generic Mechanical Design Criteria for BWR Fuel 1

Designs May 1995

ANP-3546P Browns Ferry Units 1, 2, and 3 LOCA Break 0

Spectrum Analysis for ATRIUM 10XM Fuel (EPU

MELLLA+)

ANP-3855P Browns Ferry Unit 2 Cycle 22 Plant Parameters 0

Document

ANP-3873P ATRIUM 10XM Fuel Rod Thermal-Mechanical 0

Evaluation for Browns Ferry Unit 2 Cycle 22

BFN-50-7001 Main Steam System 36

BFN-50-7023 Design Criteria Document for the Residual Heat 31

Removal Service Water System

BFN-50-7032 CONTROL AIR SYSTEM 17

BFN-50-7063 STANDBY LIQUID CONTROL SYSTEM 20

BFN-50-7064D PRIMARY CONTAINMENT ISOLATION SYSTEM 17

BFN-50-7073 High Pressure Coolant Injection System 30

BFN-50-7074 Residual Heat Removal System 30

BFN-50-7085 Design Criteria Document for the Control Rod Drive 14

System

BFN-50-738 Primary & Secondary Containment Penetrations 11

BFN-VTD-A585-0010 INSTRUCTION MANUAL FOR 4

INSTALLATION/MAINTENANCE OF 26 MAIN

STEAM ISOLATION VALVE

BFN-VTD-A585-0030 MAIN STEAM ISOLATION VALVE ATWOOD & 25

MORRILL CO., INC

BFN-VTD-A613-0080 INSTALLATION AND MAINTENANCE MANUAL 0

FOR AUTOMATIC VALVE NUMBER D7179-004

BFN-VTD-C515-0020 Instruction Manual for Conax Corp Valve 1832-117-3

01, 1832-117-02

BFN-VTD-C515-0030 Installation and Maintenance Manual Valve P/N 4

Inspection Type Designation Description or Title Revision or

Procedure Date

7048-1700-01 and Replacement Kits P/N N-27006-

01, P/N N-27006-01A and P/N N-27006-03

BFN-VTD-C635-0080 Copes Vulcan Vendor Manual 1

BFN-VTD-F990-0050 Instruction Manual For Flowserve 10 - 900 Lb. 8

Double Disk Gate Valves Models No# W0025603 &

W25604

BFN-VTD-L200-0260 Limitorque Vendor Manual 8

BFN-VTD-W030-0030 Walworth Vendor Manual 20

BFN-VTD-W993-0080 INSTRUCTION MANUAL FOR INSTALLATION / 5

MAINTENANCE 26 MAIN STEAM ISOLATION

VALVE

DOWG 16-01 RESOURCE MANUAL FOR IP-ENG-001, 11/12/2018

STANDARD DESIGN PROCESS

DS-M18.14.1 Design Standard for Environmental Qualification of 6

Electrical Equipment in Harsh Environments

DS-M18.2.23 Air Operated Valve Design Basis Reviews 2

EPRI 3002010639 Nuclear Maintenance Applications Center: October

Application Guide for Main Steam Isolation Valves2017

FMS-Air Operated Fleet Maintenance Strategy Air Operated Valves- 0

Valves-1 Diaphragm and Piston Type with Accessories and

Valve Body

FS1-0044279 10 CFR 50.46 PCT Error Report for Browns Ferry 1

Units 1, 2, and 3 with EPU/MELLLA+ Conditions

G-106 General Engineering Specification, Engineering 0

Requirements For Generic Valve Packing

Substitution

G-50 General Engineering Specification - Torque, Thrust 12

and Control Switch

Settings for Motor-Operated Valves

GE-APED-5608 GENERAL ELECTRIC COMPANY ANALYTICAL April 1968

AND EXPERIMENTAL PROGRAMS FOR

RESOLUTION OF ACRS SAFETY CONCERNS

GE-APED-5750 DESIGN AND PERFORMANCE OF GENERAL March 1969

ELECTRIC BOILING WATER REACTOR MAIN

Inspection Type Designation Description or Title Revision or

Procedure Date

STEAM LINE ISOLATION VALVES

NDQ0999980003 Analytical Limits for RPS/ECCS/LOCA Analysis, 17

Actions, and Permissives

NPG-SPP-09.1.20 Inservice Testing Program Requirements 1

NPG-SPP-09.26.13 Air Operated Valve Program 1

NPG-SPP-09.3 Plant Modifications and Engineering Change Control38

NPG-SPP-09.31 Containment Leak Rate Programs 0

NUREG-1465 Accident Source Terms for Light-Water Nuclear February

Power Plants 1995

PEG PKG NO. 161021-TRIGGER ASSEMBLY REPLACEMENT PARTS 1

BFNM0 KIT, QA 1, VALVE, EXPLOSIVE TYPE, STANDBY

LIQUID CONTROL (SLC), SYSTEM 063, CONAX

DRAWING N27006, MIRION TECHNOLOGIES

CONAX NUCLEAR INC (FORMERLY IST CONAX

NUCLEAR)

System 23 Health Report March 2022

System 74 Health Report May 2022

System 85 Health Report April 2022

Procedures 0-AOI-32-1 Loss of Control and Service Air Compressors 57

0-TI-360 Containment Leak Rate Programs 50

0-TI-362 Inservice Testing Program 62

0-TI-636 MOV Motor Operated Valve Testing and 1

Maintenance Instruction

1-OI-74 Residual Heat Removal System 120

1-SR-3.1.8.2 Scram Discharge Volume Valves Operability 23

1-SR-3.3.3.1.4(H1) Verification of Remote Position Indicators for 11

Residual Heat Removal System I Valves

1-SR-3.3.3.2.1(85) Backup Control Panel Testing and Verification of 1

Remote Position Indicators for SDV Vent & Drain

Valves

1-SR-3.6.1.3.S(RHR I) RHR System MOV Operability Loop I 26

2-EOI Appendix-6B Injection Subsystem Lineup RHR System I LPCI 12

Mode

2-SI-3.2.10.113 Verification of Remote Position Indicators for 20

Inspection Type Designation Description or Title Revision or

Procedure Date

RHRSW System Valves

2-SI-4.5.C.1(D) RHRSW HxD Valves Quarterly IST Test 9

2-SR-3.3.1.1.13(OUTBD) Outboard MSIV Limit Switch Calibration and Slow 15

Speed Adjustment

BFN-2-MVOP-023-0052 Periodic Verification (PV) MOVATS Test 12/13/2019

MMTP-144 MOV Diagnostic Testing, 2-MVOP-023-0052 03/19/2021

MMTP-154 Air Operated Valve Diagnostic Testing 0

NPG-SPP-22.001 Effectiveness Review 2

NPG-SPP-22.600 Issue Resolution 13

PM 54860 BFN-1-MVOP-074-0052 Periodic Verification 08/06/2021

Testing (PV) On-Line Revision

Work Orders 118926036, 119853968,

09-716654-000,

20972584, 121991695,

114823739, 118961122,

20268127, 121435552,

20251406, 118168698,

21136761, 120736347,

21229133, 121206244,

119122816, 119819503,

20300764, 120300770,

20251523, 120251590,

20591515, 120592995,

21053073, 119880890,

119122868, 121323511,

2138983, 119880890,

21309337, 121516224,

20837729, 122003289,

2003287, 121788877,

21471701, 121333011,

118349424, 118491281,

119644368, 122168116,

118604496, 119187337,

119184961, 119686202,

Inspection Type Designation Description or Title Revision or

Procedure Date

21999390, 122002010,

2123460, 122002003,

20623040

21