IR 05000298/2024002

Integrated Inspection Report 05000298/2024002

ML24206A141
Person / Time
Site:	Cooper
Issue date:	07/25/2024
From:	Jeffrey Josey NRC/RGN-IV/DORS/PBC
To:	Dia K Nebraska Public Power District (NPPD)
References
IR 2024002
Download: ML24206A141 (33)

Text

July 25, 2024

SUBJECT:

COOPER NUCLEAR STATION - INTEGRATED INSPECTION REPORT 05000298/2024002

Dear Khalil Dia:

On June 30, 2024, the U.S. Nuclear Regulatory Commission (NRC) completed an inspection at Cooper Nuclear Station. On July 18, 2024, the NRC inspectors discussed the results of this inspection with you and other members of your staff. The results of this inspection are documented in the enclosed report.

Five findings of very low safety significance (Green) are documented in this report. Five of these findings involved violations of NRC requirements. We are treating these violations as non-cited violations (NCVs) 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 IV; the Director, Office of Enforcement; and the NRC Resident Inspector at Cooper Nuclear Station.

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 IV; and the NRC Resident Inspector at Cooper Nuclear Station. 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, Jeffrey E. Josey, Chief Reactor Projects Branch C Division of Operating Reactor Safety Docket No. 05000298 License No. DPR-46

Enclosure:

As stated

Inspection Report

Docket Number: 05000298

License Number: DPR-46

Report Number: 05000298/2024002

Licensee: Nebraska Public Power District

Facility: Cooper Nuclear Station

Location: Brownville, NE

Inspection Dates: April 1, 2024, to June 30, 2024

Inspectors: G. Birkemeier, Resident Inspector K. Chambliss, Senior Resident Inspector J. Fiske, Emergency Preparedness Specialist S. Hedger, Senior Emergency Preparedness Inspector H. Strittmatter, Resident Inspector T. Weir, Physical Security Inspector

Approved By: Jeffrey E. Josey, Chief Reactor Projects Branch C Division of Operating Reactor Safety

Enclosure

SUMMARY

The U.S. Nuclear Regulatory Commission (NRC) continued monitoring the licensees performance by conducting an integrated inspection at Cooper Nuclear Station, 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.

List of Findings and Violations

Failure to Evaluate Safety-Related Rosemount Transmitters for Environmental Qualification Cornerstone Significance Cross-Cutting Report Aspect Section Mitigating Green None (NPP) 71111.15 Systems NCV 05000298/2024002-01 Open/Closed The inspectors identified a finding of very low safety significance (Green) and an associated non-cited violation of Title 10 of the Code of Federal Regulations 50.49, Environmental Qualification of Electrical Equipment Important to Safety for Nuclear Power Plants, for the licensees failure to qualify an item of electrical equipment important to safety by acceptable methods. Specifically, installed Rosemount transmitters were not in the configuration qualified by the licensees environmental qualification reports. Since the configuration in the plant is not in accordance with the environmental qualification report, the licensee is required to qualify the Rosemount transmitters by one of the methods as described in Title 10 of the Code of Federal Regulations 50.49 to qualify the configuration in the plant.

Failure to Specify Installation Requirements Resulting in A Non-Qualified Configuration Cornerstone Significance Cross-Cutting Report Aspect Section Mitigating Green [H.11] - 71111.15 Systems NCV 05000298/2024002-02 Challenge the Open/Closed Unknown The inspectors reviewed a self-revealed finding of very low safety significance (Green) and an associated non-citied violation of Technical Specifications 5.4.1.a, "Instructions, Procedures, and Drawings," for the licensee's failure to implement maintenance that can affect the performance of safety-related equipment without properly preplanning and performing the maintenance in accordance with written procedures, documented instructions, or drawings appropriate to the circumstances. Specifically, the work instructions for the installation of the auxiliary oil pump start/stop pressure switch failed to incorporate torque specifications for the mounting of a seismically qualified component.

Inadequate Post Work Testing Resulting in a Failure to Identify a Deficiency Introduced During Maintenance Cornerstone Significance Cross-Cutting Report Aspect Section Mitigating Green [H.8] - 71111.24 Systems NCV 05000298/2024002-03 Procedure Open/Closed Adherence The inspectors identified a finding of very low safety significance (Green) and an associated non-cited violation for the licensee's post-work testing, which failed to meet the requirements of 10 CFR Part 50, Appendix B, Criterion XI. The inadequate post-work testing resulted in a failure to identify a condition adverse to quality. Specifically, post-work testing for the residual heat removal service water booster pump subsystem failed to include adequate testing for safety-related bearings that were replaced during maintenance activities resulting in the bearing becoming overheated during a scheduled residual heat removal service water booster pump run and the residual heat removal service water booster pump being declared inoperable.

Failure to Adequately Assess Preventive Maintenance Frequency Change Resulting in a High-Pressure Coolant Injection Through-Wall Leak Cornerstone Significance Cross-Cutting Report Aspect Section Mitigating Green None (NPP) 71153 Systems NCV 05000298/2024002-04 Open/Closed The inspectors reviewed a self-revealed finding of very low safety significance (Green) and an associated non-citied violation of Technical Specification 5.4.1.a, "Procedures," for the licensee's failure to implement a preventive maintenance schedule developed to specify inspection or replacement of parts that have a specific lifetime. Specifically, the main turbine bypass valve preventive maintenance schedule failed to consider increased flow-accelerated corrosion and erosion of downstream piping of the high-pressure coolant injection steam trap when justifying extending the preventive maintenance frequency of the stream trap resulting in a through-wall leak in the high-pressure coolant injection steam trap discharge piping which resulted in high-pressure coolant injection being inoperable.

Failure to Translate the Design Requirements into Plant Configuration Cornerstone Significance Cross-Cutting Report Aspect Section Mitigating Green None (NPP) 71153 Systems NCV 05000298/2024002-05 Open/Closed The inspectors identified a finding of very low safety significance (Green) and an associated non-cited violation of 10 CFR Part 50, Appendix B, Criterion III, Design Control, for the licensees failure to translate design requirements for the main turbine stop valve reactor protection system limit switches. Specifically, the licensee did not design and install the reactor protection system limit switches with mechanical separation as required by FSAR, section VII-2.3.6.4, nor channel separation as required by Technical Specifications 3.3.1.1.

Additional Tracking Items

Type Issue Number Title Report Section Status LER 05000298/2023-002-01 Secondary Containment 71153 Closed Differential Pressure Perturbation Exceeds Technical Specifications LER 05000298/2024-003-00 High Pressure Coolant 71153 Closed Injection Steam Leak Causes Condition that Could Have Prevented Fulfillment of a Safety Function and a Condition Prohibited by Technical Specifications LER 05000298/2024-004-00 Main Turbine Stop Valve 71153 Closed Position Switches Do Not Meet Channel Independence Criteria Results in Two Channels Being Declared Inoperable and A Condition Prohibited by Technical Specifications

PLANT STATUS

Cooper Nuclear Station began the inspection period at rated thermal power. On May 17, 2024, power was lowered to approximately 70 percent for a planned rod pattern adjustment. The plant returned to rated thermal power on May 18, 2024. On June 21, 2024, power was lowered to approximately 70 percent for a planned rod pattern adjustment. The plant returned to rated thermal power on June 22, 2024. The unit remained at rated thermal power for the remainder of the inspection period.

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 performed activities described in IMC 2515, Appendix D, Plant Status, observed risk-significant activities, and completed on-site portions of IPs. 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.

71111.01 - Adverse Weather Protection

Seasonal Extreme Weather Sample (IP Section 03.01) (1 Sample)

(1) The inspectors evaluated readiness for seasonal extreme weather conditions prior to the onset of seasonal hot temperatures for the following systems:

• offsite power sources on June 18, 2024

Impending Severe Weather Sample (IP Section 03.02) (1 Sample)

(1) The inspectors evaluated the adequacy of the overall preparations to protect risk-significant systems from impending severe weather during National Weather Service forecasted severe thunderstorms with elevated risk of large hail, tornados, and gusting winds on May 5, 2024.

71111.04 - Equipment Alignment

Partial Walkdown Sample (IP Section 03.01) (5 Samples)

The inspectors evaluated system configurations during partial walkdowns of the following systems/trains:

(1) division 2 emergency diesel generator on May 1, 2024

(2) high-pressure coolant injection on May 2, 2024

(3) division 1 standby gas treatment on May 30, 2024

(4) division 2 125 Vdc battery system on June 25, 2024

(5) division 1 core spray on June 25, 2024

71111.05 - Fire Protection

Fire Area Walkdown and Inspection Sample (IP Section 03.01) (5 Samples)

The inspectors evaluated the implementation of the fire protection program by conducting a walkdown and performing a review to verify program compliance, equipment functionality, material condition, and operational readiness of the following fire areas:

(1) auxiliary relay room, 903-foot 6-inch elevation, on May 28, 2024

(2) reactor building critical switchgear room 1G, 932-foot elevation, on May 28, 2024

(3) division 1 residual heat removal heat exchanger room on June 24, 2024

(4) reactor building reactor equipment cooling area, 931-foot elevation, on June 26, 2024

(5) fire pump building, 903-foot 6-inch elevation, on June 26, 2024

71111.06 - Flood Protection Measures

Flooding Sample (IP Section 03.01) (1 Sample)

(1) The inspectors evaluated internal flooding mitigation protections in the:

• control building basement on May 17, 2024

71111.11Q - Licensed Operator Requalification Program and Licensed Operator Performance

Licensed Operator Performance in the Actual Plant/Main Control Room (IP Section 03.01) (1 Sample)

(1) The inspectors observed and evaluated licensed operator performance in the control room during quarterly down power for core management and scram rod timing on May 18, 2024.

Licensed Operator Requalification Training/Examinations (IP Section 03.02) (1 Sample)

(1) The inspectors observed and evaluated the simulator emergency preparedness scenario on April 16, 2024.

71111.12 - Maintenance Effectiveness

Maintenance Effectiveness (IP Section 03.01) (1 Sample)

The inspectors evaluated the effectiveness of maintenance to ensure the following structures, systems, and components (SSCs) remain capable of performing their intended function:

(1) corrective actions for repeat failure of maintenance rule function MS-F04 components on June 28, 2024

71111.13 - Maintenance Risk Assessments and Emergent Work Control

Risk Assessment and Management Sample (IP Section 03.01) (4 Samples)

The inspectors evaluated the accuracy and completeness of risk assessments for the following planned and emergent work activities to ensure configuration changes and appropriate work controls were addressed:

(1) planned Yellow risk during division 1 residual heat removal maintenance window on May 17, 2024

(2) planned Yellow online risk during emergency diesel generator division 2 maintenance window and emergent work identified during maintenance window on May 25, 2024

(3) planned Yellow risk during high-pressure coolant injection special testing on May 25, 2024

(4) planned Yellow online risk during emergency diesel generator division 2 maintenance window on June 27, 2024

71111.15 - Operability Determinations and Functionality Assessments

Operability Determination or Functionality Assessment (IP Section 03.01) (5 Samples)

The inspectors evaluated the licensee's justifications and actions associated with the following operability determinations and functionality assessments:

(1) configuration of reactor water level transmitter process drain lines on June 18, 2024

(2) division 2 emergency diesel generator jacket water low discharge pressure on June 19, 2024

(3) high-pressure coolant injection pressure switch seismic qualification on June 24, 2024

(4) average power range monitor power supplies seismic qualification on June 24, 2024

(5) repair of high-pressure coolant injection drain line steam leak on June 28, 2024

71111.18 - Plant Modifications

Temporary Modifications and/or Permanent Modifications (IP Section 03.01 and/or 03.02) (2 Samples)

The inspectors evaluated the following temporary or permanent modifications:

(1) division 2 emergency diesel generator engine driven fuel pump replacement on June 20, 2024

(2) division 1 emergency diesel generator jacket water flange modification on June 28, 2024

71111.24 - Testing and Maintenance of Equipment Important to Risk

The inspectors evaluated the following testing and maintenance activities to verify system operability and/or functionality:

Post-Maintenance Testing (PMT) (IP Section 03.01) (4 Samples)

(1) reactor core isolation cooling quarterly test for maintenance window post work testing on June 2, 2024

(2) high-pressure coolant injection maintenance window post testing on June 27, 2024

(3) post work testing on control building basement flood detector following swap of 2-inch and 8-inch relays on June 28, 2024

(4) residual heat removal service water booster pump D post work testing following pump rebuild on June 30, 2024

Surveillance Testing (IP Section 03.01) (3 Samples)

(1) reactor core isolation cooling valve operability and timing surveillance on June 1, 2024

(2) high-pressure coolant injection special testing on June 1, 2024

(3) division 1 reactor water clean-up high flow channel calibration on June 10, 2024

71114.04 - Emergency Action Level and Emergency Plan Changes

Inspection Review (IP Section 02.01-02.03) (1 Sample)

(1) The inspectors evaluated the following emergency plan changes:

• EPIP 5.7.1, Emergency Classification, revision 73 [NRC notified on January 17, 2024 (Agencywide Documents Access and Management System

[ADAMS] Accession No. ML24016A183)]

• Emergency Plan for Cooper Nuclear Station, revision 82 [NRC notified on May 23, 2024 (ML24144A181)]

• Prompt Alert Notification System Design Report for Cooper Nuclear Station, revision 19 [NRC notified on May 23, 2024 (ML24144A181)]

This evaluation does not constitute NRC approval.

71114.06 - Drill Evaluation

Additional Drill and/or Training Evolution (1 Sample)

The inspectors evaluated:

(1) emergency preparedness drill on June 15, 2024

71114.07 - Exercise Evaluation - Hostile Action (HA) Event

Inspection Review (IP Section 02.01 - 02.11) (1 Sample)

(1) The inspectors observed the biennial emergency plan exercise conducted on May 21, 2024. The exercise scenario involved hostile action events, including simulated site impact by several small aircraft. This resulted in a rapid escalation to a Site Area Emergency classification; activation of alternative response facilities, coordination to move plant staff into the plant for damage assessment with law enforcement; response actions to lowering spent fuel pool level; and a simulated radiological release off site.

71114.08 - Exercise Evaluation - Scenario Review

Inspection Review (IP Section 02.01 - 02.04) (1 Sample)

(1) The inspectors reviewed the licensee's preliminary exercise scenario that was submitted to the NRC on March 21, 2024 (ML24081A287), for the exercise scheduled on May 21, 2024. The inspectors discussed the preliminary scenario comments with Matthew Nee, Manager, Emergency Preparedness, and other members of the emergency preparedness staff on April 17, 2024. The inspectors' review does not constitute NRC approval of the scenario.

OTHER ACTIVITIES - BASELINE

===71151 - Performance Indicator Verification

The inspectors verified licensee performance indicators submittals listed below:

BI01: Reactor Coolant System (RCS) Specific Activity Sample (IP Section 02.10)===

(1) April 1, 2023, through March 31, 2024

BI02: RCS Leak Rate Sample (IP Section 02.11) (1 Sample)

(1) April 1, 2023, through March 31, 2024

EP01: Drill/Exercise Performance (DEP) Sample (IP Section 02.12) (1 Sample)

(1) April 1, 2023, through March 31, 2024

EP02: Emergency Response Organization (ERO) Drill Participation (IP Section 02.13) (1 Sample)

(1) April 1, 2023, through March 31, 2024

EP03: Alert And Notification System (ANS) Reliability Sample (IP Section 02.14) (1 Sample)

(1) April 1, 2023. through March 31, 2024

71152A - Annual Follow-up Problem Identification and Resolution Annual Follow-up of Selected Issues (Section 03.03)

The inspectors reviewed the licensees implementation of its corrective action program related to the following issues:

(1) part 21 evaluation programmatic review on June 18, 2024

71153 - Follow Up of Events and Notices of Enforcement Discretion Event Report (IP Section 03.02)

The inspectors evaluated the following licensees event reporting determinations to ensure it complied with reporting requirements.

(1) LER 05000298/2023-002-01, Secondary Containment Differential Pressure Perturbation Exceeds Technical Specifications (ML24158A065). The circumstances surrounding this LER and a self-revealed, Green, non-cited violation is documented in Inspection Report 05000298/2023004 (ML24038A256) under Inspection Results section 71111.15. This LER is Closed.

(2) LER 05000298/2024-003-00, High Pressure Coolant Injection Steam Leak Causes Condition that Could Have Prevented Fulfillment of a Safety Function and a Condition Prohibited by Technical Specifications (ML24113A090). The circumstances surrounding this LER and a Green, non-cited violation is documented in this report under Inspection Results section 71153. This LER is Closed.

(3) LER 05000298/2024-004-00, Main Turbine Stop Valve Position Switches Do Not Meet Channel Independence Criteria Results in Two Channels Being Declared Inoperable and a Condition Prohibited by Technical Specifications (ML24131A023).

The circumstances surrounding this LER and a Green, non-cited violation is documented in this report under Inspection Results section 71153. This LER is Closed.

INSPECTION RESULTS

Failure to Evaluate Safety-Related Rosemount Transmitters for Environmental Qualification Cornerstone Significance Cross-Cutting Report Aspect Section Mitigating Green None (NPP) 71111.15 Systems NCV 05000298/2024002-01 Open/Closed The inspectors identified a finding of very low safety significance (Green) and an associated non-cited violation of Title 10 of the Code of Federal Regulations 50.49, Environmental Qualification of Electrical Equipment Important to Safety for Nuclear Power Plants, for the licensees failure to qualify an item of electrical equipment important to safety by acceptable methods. Specifically, installed Rosemount transmitters were not in the configuration qualified by the licensees environmental qualification reports. Since the configuration in the plant is not in accordance with the environmental qualification report, the licensee is required to qualify the Rosemount transmitters by one of the methods as described in Title 10 of the Code of Federal Regulations 50.49 to qualify the configuration in the plant.

Description:

During a walkdown of the plant, the inspectors identified a discrepancy between the configuration of process lines to Rosemount 1153 transmitters installed in environmentally qualified applications and the configuration qualified for use in harsh environments by the manufacturer.

The vendor manual design specification for Rosemount 1153 transmitters contains a note stating, customer assumes responsibility for qualifying process interfaces on these options,"

for configurations that do not include the Swagelok process connection configuration specified in the qualification report. The vendor provided a specific model configuration that was environmentally qualified and other model configurations requiring end user qualification.

The inspectors identified that a number of the Rosemount 1153 transmitters, installed in the plant, were not in the vendor qualified configuration. As a result, per vendor instructions, the end user is required to environmentally qualify these alternate configurations in accordance with one of four methods listed in 10 CFR 50.49. The licensee has no documentation to support the qualification of these installed alternate configurations using one of the four methods listed.

NUREG 0588 and IEEE Standard 323-1974 both state that to meet Regulator Guide 1.89 requirements, environmental qualification for electrical components needs to include the process connections, whose failure could result in the failure of the instrument.

Therefore, the inspectors concluded that these specific transmitter configurations had not been environmentally qualified by the licensee. As a result, there is no assurance that these components could be relied upon to perform the required function for the specified mission time under all accident conditions.

Corrective Actions: Cooper will update the Rosemount 1153B series transmitter EQDP.3.108, Sect. F to evaluate the process connection and incorporate vendor recommendations.

Instructions will be included for torque values, thread sealants, required hardware interface and other requirements.

Corrective Action References: Condition Report CR-CNS-2024-01230

Performance Assessment:

Performance Deficiency: Failure to maintain equipment required to be environmentally qualified is reasonably in the licensee ability to foresee and correct and therefore a performance deficiency.

Screening: The inspectors determined the performance deficiency was more than minor because it was associated with the Equipment Performance attribute of the Mitigating Systems cornerstone and adversely affected the cornerstone objective to ensure the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences. Specifically, the licensee failed to ensure the installed configuration of transmitters were environmentally qualified in order to perform their safety function.

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," the inspectors determined this finding to be of very low safety significance (Green) because it was a deficiency affecting the design or qualification of equipment, but the equipment maintained its probabilistic risk assessment (PRA) functionality.

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. The inspectors determined that the last installation of Rosemount 1153s in a non-qualified configuration occurred in 2019. Therefore, the performance deficiency is not indicative of current licensee performance.

Enforcement:

Violation: Title 10 CFR 50.49, Environmental Qualification of Electrical Equipment Important to Safety for Nuclear Power Plants, section

(f) requires that each item of electric equipment important to safety must be qualified by one of the following methods:

(1) Testing an identical item of equipment under identical conditions or under similar conditions with a supporting analysis to show that the equipment to be qualified is acceptable.

(2) Testing a similar item of equipment with a supporting analysis to show that the equipment to be qualified is acceptable.

(3) Experience with identical or similar equipment under similar conditions with a supporting analysis to show that the equipment to be qualified is acceptable.

(4) Analysis in combination with partial type test data that supports the analytical assumptions and conclusions.

Contrary to the above since 1974 to June 30, 2024, the licensee failed to qualify an item of electrical equipment important to safety by one of the following methods:

(1) Testing an identical item of equipment under identical conditions or under similar conditions with a supporting analysis to show that the equipment to be qualified is acceptable.

(2) Testing a similar item of equipment with a supporting analysis to show that the equipment to be qualified is acceptable.

(3) Experience with identical or similar equipment under similar conditions with a supporting analysis to show that the equipment to be qualified is acceptable.

(4) Analysis in combination with partial type test data that supports the analytical assumptions and conclusions.

Specifically, the licensee has numerous Rosemount transmitters, important to safety, installed in multiple systems in a configuration that the licensee has not qualified that may not perform their intended function under the environmental conditions described by 10 CFR 50.49.

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

Failure to Specify Installation Requirements Resulting in A Non-Qualified Configuration Cornerstone Significance Cross-Cutting Report Aspect Section Mitigating Green [H.11] - 71111.15 Systems NCV 05000298/2024002-02 Challenge the Open/Closed Unknown The inspectors reviewed a self-revealed finding of very low safety significance (Green) and an associated non-citied violation of Technical Specifications 5.4.1.a, "Instructions, Procedures, and Drawings," for the licensee's failure to implement maintenance that can affect the performance of safety-related equipment without properly preplanning and performing the maintenance in accordance with written procedures, documented instructions, or drawings appropriate to the circumstances. Specifically, the work instructions for the installation of the auxiliary oil pump start/stop pressure switch failed to incorporate torque specifications for the mounting of a seismically qualified component.

Description:

On March 14, 2023, the licensee installed a new model pressure switch for the high-pressure coolant injection (HPCI) auxiliary oil pump. The safety function of the pressure switch is to secure the auxiliary oil pump at 85 psig to prevent over-pressurization of the downstream piping and components and to provide a start signal for the auxiliary pump upon coast-down of the HPCI turbine at 20 psig. The auxiliary oil pump provides lubrication and cooling of equipment and bearings and provides control and hydraulic oil to the turbine governor system upon startup of the HPCI turbine until the shaft-driven oil pump can provide adequate pressure for oil supply.

On March 13, 2024, during a HPCI maintenance window, the pressure switch open contact was found to be calibrated at 47.12 psig and could not be adjusted to the acceptable value, resulting in a condition which would have secured the auxiliary oil pump prior to the desired setpoint of 85 psig. Further investigation revealed the pressure switch was not mounted as specified in the applicable qualification test report, EGS-TR-HC2132-02, which specified a torque value of 9 in-lbs for the nut, and the usage of 1/4" - 20 screws, a flat washer and a lock washer. Work Order (WO) 5393705 failed to specify the torque requirement listed in the qualification test report and did not specify the usage of the flat washer or lock washer.

Additionally, during installation the licensee failed to remove a rubber gasket from the previously installed mounting plate, which was not part of the qualified configuration of the new model pressure switch (9012G). As a result, a subcomponent of HPCI, the auxiliary oil pump, was rendered inoperable. Therefore, HPCI was inoperable from March 14, 2023, when the pressure switch was installed, until the system was returned to service following post maintenance testing on March 15, 2024.

As part of investigation, the vendor replicated the as-found mounting configuration and confirmed the over-torquing caused the instrument to be out of tolerance. The vendor also confirmed the condition did not affect the calibration of the closed contact (start signal) at 20 psig system pressure. The licensee confirmed the degraded auxiliary oil pump discharge pressure would be sufficient to supply oil to the turbine stop valve, hydraulic actuator, and pump bearings. Additionally, on April 22, 2024, the licensee conducted a test using a special procedure to validate HPCI would be capable of performing its safety function with the pressure switch in its as-found calibration. With the pressure switch open contacts set to 46.53 psig, SP-24-03, HPCI system functional test for HPCI-PS-2787, successfully demonstrated the auxiliary oil pump would supply sufficient lubrication and turbine governor oil supply to start the HPCI turbine until the shaft-driven oil pump came up to speed.

On May 13, 2024, the licensee issued Licensee Event Report 2024-005-00 documenting the condition prohibited by Technical Specification (TS) 3.5.1, conditions C and G. Condition C, which is entered when HPCI is inoperable, requires verification by administrative means that the reactor core isolation cooling (RCIC) system is operable within 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> and restoration of HPCI to operable within 14 days. Condition G, which is entered when completion time of condition C is not met, requires Mode 3 entry within 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> and reduction of reactor steam dome pressure to less than or equal to 150 psig within 36 hours4.166667e-4 days <br />0.01 hours <br />5.952381e-5 weeks <br />1.3698e-5 months <br />. Condition H, which is entered when the HPCI system and one or more automatic depressurization system (ADS)valves inoperable, requires limiting condition for operation (LCO) 3.0.3 to be entered immediately.

From March 28, 2023, until March 15, 2024, the licensee was in a condition prohibited by TS 3.5.1, conditions C and G, for failing to restore HPCI system to operable status within 14 days and failing to be in MODE 3. On May 12, 2023, August 11, 2023, November 9, 2023, and February 9, 2024, the licensee was in a condition prohibited by technical specifications, TS 3.5.1 condition H, for failing to enter LCO 3.0.3, which requires the licensee be in Mode 2 within 7 hours8.101852e-5 days <br />0.00194 hours <br />1.157407e-5 weeks <br />2.6635e-6 months <br />, Mode 3 within 13 hours1.50463e-4 days <br />0.00361 hours <br />2.149471e-5 weeks <br />4.9465e-6 months <br />, and Mode 4 within 37 hours4.282407e-4 days <br />0.0103 hours <br />6.117725e-5 weeks <br />1.40785e-5 months <br />, immediately upon declaring ADS valves inoperable for testing while HPCI was inoperable.

Based upon the above information the inspectors determined the following:

Contrary to Technical Specification 5.4.1.a and Regulatory Guide 1.33, the site did not properly utilize qualification test report guidance for developing work instructions for the installation of a HPCI system pressure switch, a safety-related component, which led to the HPCI auxiliary oil pressure switch being inoperable for a period prohibited by Technical Specification 3.5.1.

Corrective Actions: The licensee entered the condition into its correction action program as Condition Report CR-CNS-2024-01035. The licensee submitted a licensee event report to the NRC to document the condition prohibited by technical specifications. Additionally, the licensee has performed an extent of condition and revised installation requirements in EQDP.2.136 to include the seismically tested configuration.

Corrective Action References: Condition Report CR-CNS-2024-01035

Performance Assessment:

Performance Deficiency: NRC Regulatory Guide 1.33, revision 2, Appendix A, section 9, provides recommendations for "Procedures for Performing Maintenance." Part a of section 9, 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. The inspectors determined that the licensee's work instructions for the installation of HPCI-PS-2787 failed to incorporate torque values specified by the vendor to maintain seismic and environmental qualification and was therefore a performance deficiency.

Screening: The inspectors determined the performance deficiency was more than minor because it was associated with the Design Control attribute of the Mitigating Systems cornerstone and adversely affected the cornerstone objective to ensure the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences. Specifically, the as-found condition of the pressure switch, which was found calibrated to actuate at a lower pressure than desired as a result of improper torquing, brought the equipment's seismic qualification into doubt.

Significance: The inspectors assessed the significance of the finding using IMC 0609, Appendix A, The Significance Determination Process (SDP) for Findings At-Power. The inspectors screened the performance deficiency using exhibit 2 - Mitigating Systems Screening Questions. The inspectors screened the performance deficiency to Green since the SSC maintained its PRA function as evidenced by HPCI system functional test for HPCI-PS-2787, SP-24-003 revision 0, performed on April 22, 2024.

Cross-Cutting Aspect: H.11 - Challenge the Unknown: Individuals stop when faced with uncertain conditions. Risks are evaluated and managed before proceeding. Specifically, the vendor seismic qualification test report, EGS-TR-HC213202, specified a washer torque value of 9 in-lbs. Contrary to the above, work management processes failed to translate the torquing requirements to EC-4947302 and the associated work order to install the pressure switch, (WO-5393705) performed on March 14, 2023. When faced with an unknown torque value on seismically qualified equipment, the licensee failed to question the lack of a requirement on multiple occasions and proceeded to tighten the nuts using "skill of the craft" and a generic maintenance Procedure 7.3.28.1, Lead removal/installation and lug installation.

Enforcement:

Violation: Technical Specification 5.4.1.a requires, in part, that written procedures shall be established, implemented, and maintained covering the applicable procedures recommended in Regulatory Guide 1.33, revision 2, Appendix A, February 1978. NRC Regulatory Guide 1.33, revision 2, Appendix A, section 9, provides recommendations for "Procedures for Performing Maintenance." Part a of section 9, 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.

WO 539705 was a work instruction the licensee used to perform replacement of the auxiliary oil pressure switch.

Technical Specification 3.5.1 LCO requires high-pressure coolant injection be operable in Modes 1 through 3, except when steam dome pressure is less than or equal to 150 psig.

Contrary to the above, on March 14, 2023, the licensee failed to establish a procedure to address the requirements of Regulatory Guide 1.33, Appendix A, section 9. Specifically, WO 5393705 did not incorporate vendor guidance specifying torque requirements for the mounting nuts. As a result, the nuts were over-tightened and caused the pressure switch to become out of calibration and compliance with its seismic and environmental qualification, rendering the pressure switch and high-pressure coolant injection inoperable. Because of this the high-pressure coolant injection LCO for operability and subsequent actions to be in Mode 3 and reduce reactor steam dome pressure were not met between March 28, 2023, and March 14, 2024.

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

Inadequate Post Work Testing Resulting in a Failure to Identify a Deficiency Introduced During Maintenance Cornerstone Significance Cross-Cutting Report Aspect Section Mitigating Green [H.8] - 71111.24 Systems NCV 05000298/2024002-03 Procedure Open/Closed Adherence The inspectors identified a finding of very low safety significance (Green) and an associated non-cited violation for the licensee's post-work testing, which failed to meet the requirements of 10 CFR Part 50, Appendix B, Criterion XI. The inadequate post-work testing resulted in a failure to identify a condition adverse to quality. Specifically, post-work testing for the residual heat removal service water booster pump subsystem failed to include adequate testing for safety-related bearings that were replaced during maintenance activities resulting in the bearing becoming overheated during a scheduled residual heat removal service water booster pump run and the residual heat removal service water booster pump being declared inoperable.

Description:

In January 2018, the licensee removed A residual heat removal (RHR) service water booster pump (SWBP) for replacement. The pump was subsequently rebuilt from November 2020 to June 2022, including replacement of the pump's shaft and bearings. The pump was reinstalled into the SWBP D location and passed all post-maintenance testing. On August 27, 2022, the outboard bearing high temperature warning alarm was received while the pump was supporting service water chemical injection, and the licensee declared the pump inoperable. The licensee entered this condition into their corrective action program as Condition Report CR-CNS-2022-03653.

The licensee's apparent cause analysis identified an increasing trend in the outboard bearing temperature, approaching high temperature warning alarm setpoints, as identified through data available on the plant's plant monitoring information system (PMIS). Specifically, during post work testing on July 29, 2022, the SWBP D outboard bearing temperature reached the historical steady-state temperature range of 150-155 degrees Fahrenheit but was continuing to increase when the pump was secured after approximately 90 minutes of run time.

When the pump was placed into service for chemical addition on August 27, 2022, the outboard bearing temperature trend was consistent with the July 29th run but continued to increase when run time exceeded 90 minutes, ultimately leading to a high temperature alarm and subsequent inoperability. Despite the availability in real time, the licensee failed to utilize PMIS data to trend outboard bearing temperature, and as a result failed to allow the outboard bearing to reach steady-state temperature as part of their post work testing and operability determination.

Additionally, station Procedure 7.0.5, "CNS Post-Maintenance Testing," revision 60, works in concert with station Procedure 0-EN-WM-107, "Post Maintenance Testing," revision 5C0, to provide guidance for the station's development of post-work testing. Section 5.2.6 of Procedure 0-EN-WM-107 states: "post maintenance testing scope should be based on extent of maintenance performed. A satisfactory test verifies that a particular component or system is able to perform its intended function, the original deficiency has been corrected, and no new deficiency has been introduced through maintenance activities." Procedure 7.0.5 states that post-work testing is the ensure a component can "perform its intended function after maintenance activities."

Based upon the above information the inspectors determined the following:

Contrary to 10 CFR Part 50, Appendix B, Criterion XI, which requires, in part, that "all testing required to demonstrate that structures, systems, and components will perform satisfactorily in service" is identified, and station Procedures 7.0.2 and 0-EN-WM-107, the post-maintenance testing developed and applied for the residual heat removal service water booster pump bearings did not prevent a new deficiency from being introduced after maintenance activities and prevented the residual heat removal service water booster pump subsystem from performing its required in-service function. Additionally, this caused an exceedance of the technical specification allowed outage time specified by TS 3.7.1 condition A.

Corrective Actions: The licensee is evaluating the post work testing for residual heat removal service water booster pumps. Actions include ensuring stabilization of bearing temperatures prior to securing post work testing and changing applicable post work testing maintenance procedures.

Corrective Action References: Condition Report CR-CNS-2024-02714

Performance Assessment:

Performance Deficiency: Title 10 CFR Part 50, Appendix B, Criterion XI, requires a test program be established to assure testing required to demonstrate structures, systems, and components will perform satisfactorily in service is identified and performed in accordance with written procedures. The licensee's failure to implement adequate post-maintenance testing activities that would provide assurance that service water booster pump subcomponents would meet their design basis functions following maintenance is a performance deficiency.

Screening: The inspectors determined the performance deficiency was more than minor because it was associated with the Equipment Performance attribute of the Mitigating Systems cornerstone and adversely affected the cornerstone objective to ensure the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences. Specifically, the licensee's post-maintenance testing was unable to demonstrate that maintenance performed on the outboard bearing of residual heat removal service water booster pump D did not adversely affect the availability, reliability, or capability of the service water booster pump.

Significance: The inspectors assessed the significance of the finding using IMC 0609, Appendix A, The Significance Determination Process (SDP) for Findings At-Power. The inspectors determined that this finding is of very low safety significance (Green) because the finding did not represent a deficiency affecting design or qualification of a mitigating structure, system, or component; did not involve the loss of a single-train TS system longer than its TS allowed outage time; did not represent the loss of PRA function one train of a multi-train system for greater than its TS allowed outage time; did not represent the loss of PRA function of two separate TS systems for greater than 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />; did not represent the loss of a PRA system and/or function as defined in the PRIB or the licensees PRA for greater than 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />; and did not represent the loss of the PRA function of one or more non-TS trains of equipment designated as risk-significant in accordance with the licensees maintenance rule program for greater than 3 days. Additionally, the finding did not involve external events mitigating systems, the reactor protection system, fire brigade, or flexible coping strategies.

Cross-Cutting Aspect: H.8 - Procedure Adherence: Individuals follow processes, procedures, and work instructions. Specifically, station Procedure 7.0.5, CNS Post Maintenance Testing, revision 60, states in part that "Post maintenance testing ensures the original deficiency has been corrected and ensures no new deficiencies have been created." Additionally, station Procedure 0-EN-WM-107, revision 5C0, states, in part, that "post maintenance testing further verifies that the original deficiency has been corrected without the introduction of any new deficiencies." Contrary to the above, the licensee failed to implement post maintenance testing following the rebuild of SWBP D outboard bearing that ensures or verifies the original deficiency had been corrected and no new deficiencies had been introduced. The inadequate post-work testing did not meet the standards set by the licensee's procedures.

Enforcement:

Violation: Title 10 CFR Part 50, Appendix B, Criterion XI, "Test Control," requires, in part, that a test program shall be established to assure that all testing required to demonstrate that SSCs will perform satisfactorily in service is identified and performed in accordance with written test procedures which incorporate the requirements and acceptance limits contained in applicable design documents.

Contrary to the above, in July 2022, the licensee failed to establish a test program to assure that all testing required to demonstrate that SSCs will perform satisfactorily in service is identified and performed in accordance with written test procedures which incorporate the requirements and acceptance limits contained in applicable design documents. Specifically, the licensee's post work testing associated with a rebuild of residual heat removal service water booster pump D failed to demonstrate that the outboard bearing would perform its safety function after being replaced resulting in the bearing becoming overheated during a scheduled RHRSWBP run and the RHRSWBP being declare inoperable.

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

Failure to Adequately Assess Preventive Maintenance Frequency Change Resulting in a HPCI Through-Wall Leak Cornerstone Significance Cross-Cutting Report Aspect Section Mitigating Green None (NPP) 71153 Systems NCV 05000298/2024002-04 Open/Closed The inspectors reviewed a self-revealed finding of very low safety significance (Green) and an associated non-citied violation of Technical Specification 5.4.1.a, "Procedures," for the licensee's failure to implement a preventive maintenance schedule developed to specify inspection or replacement of parts that have a specific lifetime. Specifically, the main turbine bypass valve preventive maintenance schedule failed to consider increased flow-accelerated corrosion and erosion of downstream piping of the high-pressure coolant injection steam trap when justifying extending the preventive maintenance frequency of the stream trap resulting in a through-wall leak in the high-pressure coolant injection steam trap discharge piping which resulted in high-pressure coolant injection being inoperable.

Description:

On February 22, 2024, Cooper Nuclear Station (CNS) discovered a through-wall leak in the HPCI system steam supply drain line piping downstream of a steam trap as result of suspected flow-accelerated corrosion (FAC) and erosion of the carbon steel piping. The Class II piping through-wall leak could have potentially resulted in a loss of the safety function for HPCI. As a result, CNS declared the HPCI system inoperable and submitted an 8-hour notification per 10 CFR 50.72(b)(3)(v)(D) to the NRC and a subsequent licensee event report per 10 CFR 50.73.

On January 31, 2024, CNS wrote Condition Report CR-CNS-2024-00453 to document a steam leak on HPCI-TP-S57 (HPCI turbine steam line trap). The station noted an audible steam leak as well as a 6-inch steam puff around the steam trap. The station considered the HPCI system operable at the time as the leak was assumed to be body-to-bonnet leakage from the steam trap which is not considered American Society of Mechanical Engineers (ASME) code leakage (leakage from mechanical connections is classified as non-code leakage). On February 10, 2024, the station performed non-Technical Specification Surveillance 15. MS.301, Steam Trap Functionality, revision 12, per WO 5435831.

HPCI-TP-S57 passed the surveillance, and no discrepancies were noted. On February 19, 2024, CNS wrote Condition Report CR-CNS-2024-00730 to document the steam leak had degraded. Again, the station declared the HPCI system operable as the steam leak was still considered to be body-to-bonnet leakage on the steam trap.

On February 22, 2024, as part of a walkdown prior to a HPCI LCO window, a station technician noted steam was coming from the piping between HPCI-TP-S57 and HPCI-V-130 (HPCI drip leg drain outlet valve). At 5:18 p.m., CNS declared HPCI inoperable due to through-wall leakage of Class II piping. The station replaced the section of piping containing HPCI-TP-S57 and HPCI-V-130. On February 24, 2024, at 9:01 p.m., CNS declared HPCI operable.

A past operability reviewed determined HPCI to be inoperable from January 31, 2024, at 6:14 a.m. until February 24, 2024, at 9:01 p.m. CNS Technical Specification LCO 3.5.1, condition C.2 requires HPCI to be restored to operable status within 14 days. If HPCI is unable to be restored within 14 days, LCO 3.5.1, condition G.1 requires the station to be in Mode 3 within 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br />. Contrary to this, the station did not enter Mode 3 by February 14, 2024, at 6:14 p.m. Based on exceeding the TS completion time, this station reported this condition to the NRC under 10 CFR 50.73(a)(2)(i)(B) as any operation or condition which was prohibited by TS.

In April 1999, CNS approved a preventive maintenance plan to replace or refurbish HPCI-TP-S57 at frequency of every 384 weeks (previously 18 months). The periodicity was chosen because the preventive maintenance was considered an inefficient use of station resources and there was no history of steam trap failures for either the HPCI or RCIC systems. However, the vendor manual ("Yarway Steam Traps, Strainers & Instrument Valve Manifolds," revision 7) recommended a periodicity of 1 year for the preventive maintenance.

CNS Procedure 7.0.2, "Preventative Maintenance Program," revision 17 (since superseded by 3-CNS-DC-324), step 7.2.3 required that "all work scope, frequency, or post-work testing changes shall be reviewed by the appropriate engineering organization." Contrary to this, the flow-accelerated corrosion and erosion program owners were not included in the review for the preventive maintenance change. As a result, considerations for increase of FAC and erosion of downstream piping were not included in the justification for the preventive maintenance frequency change.

The steam trap had been in service for 4 years and 10 months prior to developing a steam leak.

Based upon the above information the inspectors determined the following:

Contrary to station procedures for the preventive maintenance program, the HPCI turbine steam line trap had a preventive maintenance frequency that deviated from the vendor manual, and the justification for the frequency failed to consider increases of FAC and erosion of downstream piping to prevent a through-wall leak of the stream trap as required by the stations TS, Regulatory Guide 1.33, and the stations preventive maintenance procedures.

Corrective Actions: The licensee entered the condition into the station's corrective action program, replaced the section of piping containing the through-wall leak, performed an extent of condition with other steam traps, and reduced the frequency of the preventive maintenance to 104 weeks for both HPCI and RCIC systems. Additionally, the station developed another preventive maintenance to clean and inspect the steam traps.

Corrective Action References: Condition Report CR-CNS-2024-00768

Performance Assessment:

Performance Deficiency: Regulatory Guide 1.33, revision 2, Appendix A, section 9, provides recommendations for "Procedures for Performing Maintenance." Part b of section 9, states, in part, that "preventative maintenance schedules should be developed to specify inspection or replacement of parts that have a specific lifetime." The inspectors determined that the licensee's preventive maintenance strategy failed to consider increased flow-accelerated corrosion and erosion of downstream piping of the high-pressure coolant injection steam trap when justifying extending the preventive maintenance frequency of the stream trap and was therefore a performance deficiency.

Screening: The inspectors determined the performance deficiency was more than minor because it was associated with the Equipment Performance attribute of the Mitigating Systems cornerstone and adversely affected the cornerstone objective to ensure the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences. Specifically, the through-wall leakage in the high-pressure coolant injection steam trap discharge piping resulted in a potential loss of safety function for the high-pressure coolant injection system.

Significance: The inspectors assessed the significance of the finding using IMC 0609, Appendix A, The Significance Determination Process (SDP) for Findings At-Power. The inspectors determined that this finding is of very low safety significance (Green) because the finding did not represent a deficiency affecting design or qualification of a mitigating structure, system, or component; did not involve the loss of a single-train TS system longer than its TS allowed outage time; did not represent the loss of PRA function one train of a multi-train system for greater than its TS allowed outage time; did not represent the loss of PRA function of two separate TS systems for greater than 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />; did not represent the loss of a PRA system and/or function as defined in the PRIB or the licensees PRA for greater than 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />; and did not represent the loss of the PRA function of one or more non-TS trains of equipment designated as risk-significant in accordance with the licensees maintenance rule program for greater than 3 days. Additionally, the finding did not involve external events mitigating systems, the reactor protection system, fire brigade, or flexible coping strategies

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:

Violation: Technical Specification 5.4.1.a requires, in part, written procedures shall be established, implemented, and maintained as covered in Regulatory Guide 1.33, revision 2, Appendix A, February 1978. Section 9.b specifies, in part, that preventive maintenance schedules should be developed to specify inspection or replacement of parts that have a specific lifetime.

Procedure 7.0.2, Preventative Maintenance Program Implementation, revision 17, implements Regulatory Guide 1.33 and provides the requirements for establishing and documenting the preventive maintenance program and assessing and justifying intent preventive maintenance frequency changes.

Technical Specification 3.5.1.C LCO requires the HPCI system be operable in Modes 1 through 3 (unless steam dome pressure is less than or equal to 150 psig).

Contrary to the above, from April 6, 1999, to July 10, 2024, preventive maintenance schedules were not developed to specify inspection or replacement of parts that have a specific lifetime. Specifically, in accordance with Cooper Nuclear Station Procedure 7.0.2, the licensee failed to consider increased flow-accelerated corrosion and erosion of downstream piping of the high-pressure coolant injection (HPCI) steam trap when justifying extending the preventive maintenance frequency of the stream trap resulting in a through-wall leak in the HPCI steam trap discharge piping which resulted in HPCI being inoperable. Because of this the HPCI LCO was not met between January 31, 2024, and February 24, 2024.

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

Failure to Translate the Design Requirements into Plant Configuration Cornerstone Significance Cross-Cutting Report Aspect Section Mitigating Green None (NPP) 71153 Systems NCV 05000298/2024002-05 Open/Closed The inspectors identified a finding of very low safety significance (Green) and an associated non-cited violation of 10 CFR Part 50, Appendix B, Criterion III, Design Control, for the licensees failure to translate design requirements for the main turbine stop valve reactor protection system limit switches. Specifically, the licensee did not design and install the reactor protection system limit switches with mechanical separation as required by FSAR, section VII-2.3.6.4, nor channel separation as required by Technical Specifications 3.3.1.1.

Description:

During inspection follow-up regarding three failed surveillances of the main turbine stop valve (TSV) limit switches which are required to function as part of the reactor protection system (RPS) TSV closure scram, the inspectors reviewed the site's current licensing and design basis for the main turbine stop valve limit switches. The inspectors questioned whether the configuration of the limit switches satisfied the requirements of CNS Updated Safety Analysis Report (USAR), section 2.3.6.4, and CNS Technical Specifications LCO 3.3.1.1. After subsequent review by the licensee, the site declared the TSV closure function inoperable.

CNS is a BWR-4 nuclear plant with a GE supplied reactor and a Westinghouse turbine generator. The turbine stop valve limit switches are NAMCO EA740 limit switches. There are four limit switches used to detect the valve position for the turbine stop valves. The safety function of the limit switches is to detect the closure of the turbine stop valves and de-energize their associated relays to initiate a reactor scram. This reactor scram is backed up by two additional RPS scram initiations: high reactor steam dome pressure and high neutron flux.

Since CNS utilizes a Westinghouse turbine, there are only two stop valves with two limit switches associated with each stop valve. In order for a scram to occur upon closure of the TSVs, one out of the two limit switches must detect when the turbine stop valve reaches 10 percent open (indicating the TSV is closing) in order for the RPS relays to de-energize.

Each stop valve must close for the RPS system to initiate the reactor scram, or "one-out-of-two taken twice" logic for the GE RPS.

Because a Westinghouse turbine only has two stop valves, upon initial construction, CNS linked one limit switch directly to the TSV positioner and connected the two limit switches with all-thread, so the limit switches actuated simultaneously. CNS USAR, section VII 2.3.6.4, describes the requirements for the interface between the turbine stop valve and RPS: "the switches on each valve are mechanically and electrically separated and satisfy IEEE-279".

Since CNS installed all-thread to connect the limit switches, this configuration did not meet the USAR requirement for mechanical separation nor did it satisfy the IEEE-279 requirements for channel independence nor single failure criterion. IEEE-279, Criteria for Protection Systems for Nuclear Power Generating Stations (1971), defines the following:

"Channel independence: Channels that provide signals for the same protective function shall be independent and physically separated to accomplish decoupling of the effects of unsafe environmental factors, electrical transients, and physical accident consequences documented in the design basis, and to reduce the likelihood of interactions between channels during maintenance operations or in the event of channel malfunction.

Single Failure Criterion: Any single failure within the protection system shall not prevent proper protective action at the system level when required."

CNS TS LCO 3.3.1.1 requires two separate channels per trip system for the TSV closure scram. On March 29, 2024, due to not meeting the channel separation requirement for TS LCO 3.3.1.1, CNS declared the TSV closure scram functional inoperable and entered TS LCO 3.3.1.1, conditions A and B, which requires placing a channel or trip system into trip within 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> for condition A and 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> for condition B. Condition D requires entering condition E if conditions A or B are not met. Condition E requires lowering reactor power below 29.5 percent within 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br />.

After declaring the TSV closure scram inoperable, the licensee requested a Notice of Enforcement Discretion (NOED) (ML24091A003) for Technical Specifications 3.3.1.1 to apply for an emergency license amendment.

The inspectors determined that the use of an all-thread to connect the two TSV limit switches was in violation of the design requirements of the facility's USAR and the channel separation requirements of the licensee's technical specifications.

Corrective Actions: The licensee entered the issue into their corrective action program and is pursuing various methods to address the mechanical separation, single failure criterion, and channel independence issues regarding the TSV limit switch.

Corrective Action References: Condition Reports CR-CNS-2024-01081 and CR-CNS-2024-01243

Performance Assessment:

Performance Deficiency: The licensee's FSAR, section VII-2.3.6.4, requires, in part, for the main turbine stop valve RPS limit switches to be mechanically separated and satisfy IEEE-279. Additionally, the licensee's Technical Specifications 3.3.1.1 requires two independent channels per subsystem for the RPS limit switches. The inspectors determined the licensee did not design nor configure the main turbine stop valve RPS limit switches in accordance with these design specifications and was therefore a performance deficiency.

Screening: The inspectors determined the performance deficiency was more than minor because it was associated with the Design Control attribute of the Mitigating Systems cornerstone and adversely affected the cornerstone objective to ensure the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences. Specifically, the licensee failed to design configure RPS limit switches in accordance with the design requirements resulting in condition prohibited by technical specifications.

Significance: The inspectors assessed the significance of the finding using IMC 0609, Appendix A, The Significance Determination Process (SDP) for Findings At-Power. The inspectors determined that the finding was of very low safety significance (Green) because the finding did affect a single RPS trip signal to initiate a reactor scram and did not affect the function of other redundant trips or diverse methods of reactor shutdown.

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:

Violation: Title 10 CFR Part 50, Appendix B, Criterion III, Design Control, requires, in part, measures shall be established to assure that applicable regulatory requirements and the design basis, as defined in 50.2 and as specified in the license application, for those structures, systems, and components to which this appendix applies are correctly translated into specifications, drawings, procedures, and instructions.

Contrary to the above, from initial construction until present, the licensee failed to establish measures to assure that applicable regulatory requirements and the design basis, as defined in 50.2 and as specified in the license application, for those structures, systems, and components to which this appendix applies were correctly translated into specifications, drawings, procedures, and instructions. Specifically, the design configuration for the main turbine stop valve RPS limit switches did not have mechanical separation as required in the licensee's USAR, section VII-2.3.6.4, nor the channel separation requirements as required in Technical Specifications 3.3.1.1.

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

EXIT MEETINGS AND DEBRIEFS

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

• On April 17, 2024, the inspectors presented the emergency preparedness exercise scenario inspection results to Matthew Nee, Manager, Emergency Preparedness, and other members of the licensee staff.

• On July 18, 2024, the inspectors presented the emergency preparedness exercise inspection results to Kahlil Dia, Site Vice President, and other members of the licensee staff.

• On July 18, 2024, the inspectors presented the integrated inspection results to Khalil Dia, Site Vice President, and other members of the licensee staff.

DOCUMENTS REVIEWED

Inspection Type Designation Description or Title Revision or

Procedure Date

71111.01 Corrective Action CR-CNS-2024-01433, 2024-01626, 2024-01629, 2024-01630

Documents

Miscellaneous Cooper 345KV Substation One-line Switching Diagram

Procedures 0-CNS-FAC-WM-Seasonal Reliability 2

016

5.1 Weather Operation during Weather Watches and Warnings 22

Work Orders WO 5441447

71111.04 Corrective Action CR-CNS-2023-00533, 2023-01782, 2023-02263, 2023-02629, 2023-

Documents 02644, 2023-03575, 2023-04087, 2024-00324, 2024-01164,

24-01458, 2024-01662

Drawings DWG 2045, Flow Diagram Core Spray System 58

Sheet 1

Miscellaneous 248495 Clearance Order

SGTA-1-WK 2422 Train A Work, Clearance Order

Procedures 2.2.25.2 125 VDC Electrical System (DIV 2) 36

2.2.33 High Pressure Coolant Injection System 92

2.2.33A High Pressure Coolant Injection System Component 33

Checklist

2.2.33B High Pressure Coolant Injection System Instrument Valve 10

Checklist

2.2.9 Core Spray System 91

2.2A.CS.DIV1 Core Spray Component Checklist (DIV 1) 5

2.2A_125DC.DIV2 125 VDC Power Checklist (DIV 2) 8

Work Orders WO 5480579

71111.05 Corrective Action CR-CNS-1996-00817, 2009-01699, 2023-01345, 2023-03376, 2023-

Documents 03496, 2024-01141, 2024-02045, 2024-02107, 2024-02108

Fire Plans CNS-FP-215 Fire Protection Pre-Fire Plan Reactor Building First Floor, 7

Elevation, 903-6

CNS-FP-217 Fire Protection Pre-Fire Plan Rx Bldg. Critical Switchgear 3

Rm 1G, Elevation 932-6

CNS-FP-218 Fire Protection Pre-Fire Plan Reactor Building Second Floor 11

Elevation 931-6

Inspection Type Designation Description or Title Revision or

Procedure Date

CNS-FP-225 Fire Protection Pre-Fire Plan Control Building Auxiliary 5

Relay Room, Elevation 903-6

CNS-FP-265 Fire Protection Pre-Fire Plan Fire Protection Pump House 4

Elevation 903-6

Procedures 0.4 Procedure Post Fire Operational Information, Revision 29 06/02/09

Change Request

for 5.4POST-FIRE

5.4POST-FIRE Post-Fire Operational Information

71111.11Q Procedures 10.9 Control Rod Scram Time Evaluation 75

2.0.3 CNS Operations Manual 107

2.1.5 Reactor Scram 79

5.5AIRCRAFT Aircraft Threat 42

5.5SECURITY Security 43

5.7.1 Emergency Classification 73

6.1MS.301 High Water Level Main Turbine Trip Channel Calibration 24

EOP-7A RPV Level (Failure-to-Scram) 23

EOP-8A RPV Control (4) 1

71111.12 Corrective Action CR-CNS-2016-07742, 2018-07736, 2018-08411

Documents

Miscellaneous Maintenance Rule Function MS-F04 Performance Criteria 7

Basis

Procedures 5.8.1 RPV Pressure Control Systems 35

5.8.12 RPV Pressure Control Systems (Failure to Scram) 35

5.8.2 RPV Depressurization Systems 54

71111.13 Miscellaneous DG-1-WK 2416 4160(1GE)

DGB-1-WK 2416 DG2

DGLO-1-5480066 DGLO

HPCI-1-HPCI WK 11

HPCI-1-TRAP STEAM LEAK

RHRA-1-RHR-Protected Equipment

SUBSYS-A WK

2419

Procedures 0-BARRIER-Reactor Building 16

Inspection Type Designation Description or Title Revision or

Procedure Date

REACTOR

0-CNS-WM-104 On-Line Schedule Risk Assessment 21

2.0.2 Operation Logs and Records 124

2.0.3 Conduct of Operations 108

71111.15 Calculations NEDC 24-001 Evaluation of HPCI Steam Line Leak Downstream of HPCI- 0

TP-S57

Corrective Action CR-CNS-2024-00768, 2024-00990, 2024-01035, 2024-01230, 2024-

Documents 01517, 2024-01522, 2024-01523, 2024-01525, 2024-01802

Drawings Burns and Roe Cooper Nuclear Station Flow Diagram Reactor Vessel 06/04/2019

26, Sheet 1 Instrumentation

CNS 115D6009 Rack 25-5 11/08/2016

CNS 450006674 Rack Mounted Instrument Piping, Tubing, and Conduit 07/16/2013

Arrangement

DWG 115D6009, Rack 25-5 Reactor Protection System & NSS System 9

Sheet 1

DWG 115D6009, Rack 25-5 Reactor Protection System & NSS System 17

Sheet 3

DWG 117C2672, Rack Mounted Instrumentation Piping 4

Sheet 1

DWG 2026, Flow Diagram Reactor Vessel Instrumentation 69

Sheet 1

DWG G5-262-743 Emergency Diesel Generator No. 1 Electrical Schematic 20

Sheet 2

DWG IL#70-3, Installation Details - Temperature Detectors for Nuclear 7

Sheet 107E Boiler Systems Leak Detection

DWG ILE70-3, Steam Leak Detection Panel #8 - Conduit Plan 21

Sheet 107

Miscellaneous Square-D Vendor Manual for Machine Tool Pressure 02/1999

Switches, 95013-008-90J

Test Report for Square D Pressure Switch Model 08/30/2016

No. 9012GBW1, EGS-TR-HC2132-02

Equipment Qualification Data Package for Square-D 0

Pressure Switch, 9012GBW1, EQDP.2.123

Polymer - EPDM Used with HPCI-PS-2787 05/01/2024

Inspection Type Designation Description or Title Revision or

Procedure Date

Part Evaluation 4309674, 20VDC Power Supply 05/27/2003

Replacement

Qualification Test Report, QTR03P1000, Revision 0 For 05/23/2002

Qualified Lambda Power Supplies

EQDP.2.136 Pressure Switch 0

EQDP.4.205 Thread Sealant (Grafoil Paste) 5

Procedures 2.2.20.1 Diesel Generator Operations 78

2.2A.DG.DIV2 Standby AC Power System (Diesel Generator) Component 9

Checklist (DIV 2)

Work Orders WO 5393705, 5479764

71111.18 Corrective Action CR-CNS-2023-00412, 2024-01492

Documents

Miscellaneous Design Equivalent Diesel Jacket Water Flange Equivalent 0

Change Package

DEC-5326168

Design Equivalent DGDO P EDF2 Hose Coupling Extension 0

Change Package

DEC-5523708

Engineering Replace DG2 Engine Driven Fuel Pump 0

Change Process

5069452

Engineering Diesel Jacket Water Flange Equivalent 0

Change Process

26168

Work Orders WO 5321366, 5487770, 5487907

71111.24 Corrective Action CR-CNS-2024-01218, 2024-01314, 2024-01411

Documents

Miscellaneous Process HPCI System Functional Test for HPCI-PS-2787 0

Applicability

Determination

Form for PAD

1. 202644

Procedures 6.1RWCU.301 PCIS RWCU High Flow Channel Calibration (DIV 1) 8

6.RCIC.102 RCIC IST and 92 Day Test 45

Inspection Type Designation Description or Title Revision or

Procedure Date

6.RCIC.201 RCIC Power Operated Valve Operability Test (IST) 32

SP24-003 HPCI System Functional Test for HPCI-PS-2787 0

Work Orders WO 5538461, 5538472

71114.04 Miscellaneous 2023-08, 2023-36, Emergency Preparedness Impact Screen and Evaluation for 02/12/2024

23-22 Emergency Plan, Revision 82

23-17 Emergency Preparedness Impact Screen for EPIP 5.7.6, 05/09/2023

Notification, Revision 87

23-23 Emergency Preparedness Impact Screen for ANS Design 02/12/2024

Report, Revision 19

24-39 Emergency Preparedness Impact Screen for EPIP 5.7.6, 03/27/2024

Notification, Revision 89

24-42 Emergency Preparedness Impact Screen for EPIP 5.7.11, 02/05/2024

Emergency Classification Process, Revision 5

24-48 Emergency Preparedness Impact Screen for EPIP 5.7.6, 04/09/2024

Notification, Revision 90

Procedures Operations Other Regulatory Reviews 35

Manual 0.29.4

71114.06 Miscellaneous Emergency Cooper Nuclear Station Qualification Drill

Preparedness Drill

Procedures 5.1INCIDENT Site Emergency Incident 49

5.5SECURITY Security 43

5.7.1 Emergency Classification 73

5.7.3 Incident Command Post (ICP) Hostile Action Based Event 3

71114.07 Corrective Action CR-CNS-2014-04876, 2014-05079, 2014-05084, 2014-05179, 2014-

Documents 05215, 2022-00028, 2022-00468, 2022-00471, 2022-01551,

22-01867, 2022-02290, 2022-02292, 2022-02916, 2022-

03322, 2022-03362, 2023-00993, 2023-02329, 2023-04444,

24-01553, 2024-01983, 2024-01991, 2024-01994, 2024-

01995, 2024-02149, 2024-02150, 2024-02151, 2024-02152,

24-02153, 2024-02154, 2024-02161

Work Tracker 2024-0006-029, 2024-0006-030, 2024-0006-031

Documents (WT-)

Corrective Action CR-CNS-2024-02003

Documents

Inspection Type Designation Description or Title Revision or

Procedure Date

Resulting from

Inspection

Miscellaneous Physical Security Plan (PSP) 11/30/2023

Law Enforcement Response Plan 11/15/2023

Cooper Nuclear Station, May 21st, 2024, Team 3 & B 06/06/2024

Graded Exercise, Management Debrief

04/16/2024 Biennial Exercise Dress Rehearsal Report 0

Procedures 0-EP-01 Emergency Response Organization Responsibilities 34

5.7.14 Stable Iodine Thyroid Blocking (KI) 24

5.7.17 CNS-Dose Assessment 54

5.7.20 Protective Action Recommendations 34

5.7.23 Activation of the Joint Information Center (JIC) 20

5.7.3 Incident Command Post (ICP) Hostile Action Based Event 3

5.7.6 Notification 90

5.7.7 Activation of TSC 44

5.7.8.2 Activation of Alternate Off-Site OSC/TSC 2

5.7.9 Activation of EOF 37

71114.08 Miscellaneous NLS2020015 Emergency Plan Full Participation Exercise Drill Scenario; 03/05/2020

Cooper Nuclear Station, Docket No. 50-298, DPR-46

NLS2022013 Emergency Plan Full Participation Exercise Drill Scenario; 03/22/2022

Cooper Nuclear Station, Docket No. 50-298, DPR-46

NLS2024020 Emergency Plan Full Participation Exercise Drill Scenario, 03/21/2024

Cooper Nuclear Station, Docket No. 50-298, DPR-46

Procedures 5.7.1 Emergency Classification 73

5.7.20 Protective Action Recommendations 31

5.7.6 Notifications 79

71151 Miscellaneous Operator Logs 2Q23 through 1Q24

BIPI Derivation Reports 2Q23 through 1Q24

Procedures 0-CNS-LI-114 Regulatory Performance Indicator Process 0

71153 Corrective Action CR-CNS-2008-06163, 2023-04582, 2023-04584, 2023-04770, 2023-

Documents 04775, 2023-04929, 2024-00019, 2024-00453, 2024-00655,

24-00730, 2024-00768, 2024-00783, 2024-00785, 2024-

01081, 2024-01243, 2024-01572,

Inspection Type Designation Description or Title Revision or

Procedure Date

Drawings DWG 2041 Flow Diagram Reactor Building Main Steam System 92

DWG 791E246, Elementary Diagram Reactor Protection System 18

Sheet 10

DWG D19237X Integral Strainer Impulse Steam Trap 0

DWG E506, Connection Wiring Diagrams Turbine Generator Building 2

Sheet 67

DWG IL#70-3, Installation Details - Temperature Detectors for Nuclear 7

Sheet 107E Boiler Systems Leak Detection

DWG ILE70-3, Steam Leak Detection Panel #8 - Conduit Plan 21

Sheet 107

Miscellaneous Maintenance Examine and Clean Trap 1999

Plan 07613

Maintenance Plan Examine and Clean Trap 2001

800000008559

VM-1034 NAMCO Composite Limit Switch & Connector Manual 13

Procedures 15.MS.301 Steam Trap Functionality 12

6.RPS.302 Main Turbine Stop Valve Closure and Steam Valve 66

Functional Test

30