IR 05000321/2024002
| ML24220A085 | |
| Person / Time | |
|---|---|
| Site: | Hatch  |
| Issue date: | 08/08/2024 |
| From: | Alan Blamey NRC/RGN-II/DRP/RPB2 |
| To: | Coleman J Southern Nuclear Operating Co |
| References | |
| IR 2024002 | |
| Download: ML24220A085 (31) | |
Text
SUBJECT:
EDWIN I HATCH NUCLEAR PLANTS UNITS 1 AND 2 - INTEGRATED INSPECTION REPORT 05000321/2024002 AND 05000366/2024002
Dear Jamie Coleman:
On June 30, 2024, the U.S. Nuclear Regulatory Commission (NRC) completed an inspection at Edwin I Hatch Nuclear Plants Units 1 and 2. On July 22, 2024, the NRC inspectors discussed the results of this inspection with Matthew Busch and other members of your staff. The results of this inspection are documented in the enclosed report.
Three findings of very low safety significance (Green) are documented in this report. Three of these findings involved violations of NRC requirements. One Severity Level IV violation without an associated finding is documented in this report. 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 II; the Director, Office of Enforcement; and the NRC Resident Inspector at Edwin I Hatch Nuclear Plants Units 1 and 2.
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 Edwin I Hatch Nuclear Plants Units 1 and 2.
August 8, 2024 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, Alan J. Blamey, Chief Reactor Projects Branch 2 Division of Reactor Projects Docket Nos. 05000321 and 05000366 License Nos. DPR-57 and NPF-5
Enclosure:
As stated
Inspection Report
Docket Numbers:
05000321 and 05000366 License Numbers:
DPR-57 and NPF-5 Report Numbers:
05000321/2024002 and 05000366/2024002 Enterprise Identifier:
I2024-002-0019 Licensee:
Southern Nuclear Operating Company, Inc.
Facility:
Edwin I Hatch Nuclear Plants Units 1 and 2 Location:
Baxley, GA Inspection Dates:
April 1, 2024 to June 30, 2024 Inspectors:
R. Easter, Resident Inspector P. Niebaum, Senior Resident Inspector Approved By:
Alan J. Blamey, Chief Reactor Projects Branch 2 Division of Reactor Projects
SUMMARY
The U.S. Nuclear Regulatory Commission (NRC) continued monitoring the licensees performance by conducting an integrated inspection at Edwin I Hatch Nuclear Plants Units 1 and 2, 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
Inadequate Installation of a Temporary Modification Resulted in Inoperable Control Room Ventilation Subsystems Cornerstone Significance Cross-Cutting Aspect Report Section Barrier Integrity Green NCV 05000321,05000366/2024002-01 Open/Closed
[H.11] -
Challenge the Unknown 71111.15 The inspectors identified a Green finding and associated non-cited violation (NCV) of unit 1 and unit 2 Technical Specification (TS) 5.4.1, Procedures, for the failure to install a temporary plant service water (PSW) modification for the main control room environmental control (MCREC) and main control room air conditioning (MCRAC) systems in accordance with written procedures. As a result, the inadequate installation of this temporary modification rendered the B MCRAC subsystem inoperable.
50.9 Violation for Providing an Inaccurate Unit 2 LER 2024-002-00 Cornerstone Severity Cross-Cutting Aspect Report Section Not Applicable Severity Level IV NCV 05000321,05000366/2024002-02 Open/Closed Not Applicable 71111.15 The inspectors identified a Severity Level (SL) IV NCV of Title 10 of the Code of Federal Regulations (CFR), Completeness and Accuracy of Information, for the licensees failure to provide complete and accurate information in all material respects for licensee event report (LER) 050366/2024-002-00, Incorrectly Installed Temporary Modification Results in a Condition Prohibited by Plant Technical Specifications, that was submitted on April 24, 2024.
Failure to Assess and Manage Risk of Conducting Maintenance on a Condensate Pump with the Main Condenser under Vacuum Cornerstone Significance Cross-Cutting Aspect Report Section Initiating Events Green NCV 05000321/2024002-03 Open/Closed
[H.12] - Avoid Complacency 71152A A Green self-revealed finding and NCV of 10 CFR 50.65(a)(4) was identified on March 11, 2024, when the licensee failed to adequately assess and manage the risk of isolating the unit 1 B (1B) condensate pump with the main condenser operating with a vacuum. As a result, air entered the condensate and feedwater systems which resulted in the trip of the running A (1A) reactor feed pump (RFP) on low suction pressure and a manual scram of the reactor due to lowering reactor vessel water level.
Failure to Develop a Preventive Maintenance Strategy Based on Site Operating Experience Cornerstone Significance Cross-Cutting Aspect Report Section Barrier Integrity Green NCV 05000321/2024002-04 Open/Closed
[P.5] -
Operating Experience 71152A A self-revealed Green finding and associated NCV of TS 3.6.1.1 was identified for failure to maintain primary containment penetration integrity. While conducting planned local leak rate testing (LLRT) of the unit 1 feedwater check valves it was determined that the primary containment leakage rate exceeded the allowable limit defined in 10 CFR 50, Appendix J,
Primary Reactor Containment Leakage Testing for Water-Cooled Power Reactors and specified in TS 5.5.12.
Additional Tracking Items
Type Issue Number Title Report Section Status LER 05000321/2024-002-00 LER 2024-002-00 for Edwin I. Hatch Nuclear Plant, Unit 1 Manual Reactor Trip Due to Loss of Feedwater 71153 Closed LER 05000321/2024-001-00 LER 2024-001-00 for Edwin I. Hatch Nuclear Plant, Unit 1, Primary Containment Penetration Exceeded Maximum Allowable Primary Containment Leakage Rate (La)71153 Closed LER 05000366/2024-002-00 LER 2024-002-00 for Edwin I. Hatch Nuclear Plant, Unit 2, Incorrectly Installed Temporary Modification Results in a Condition Prohibited by Plant Technical Specifications 71153 Closed LER 05000321,05000366/20 24-002-01 LER 2024-002-01 for Edwin I. Hatch Nuclear Plant, Unit 1
& 2, Incorrectly Installed Temporary Modification Results in Multiple Conditions Prohibited by Plant Technical Specifications 71153 Closed
PLANT STATUS
Unit 1 operated at or near rated thermal power for the entire inspection period with limited exceptions for planned evolutions such as a rod pattern adjustment and a rod sequence exchange. Additionally, there were no unplanned down powers greater than 20 percent during the inspection period.
Unit 2 operated at or near rated thermal power for the entire 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 onsite 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.
REACTOR SAFETY
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 hot weather for the following systems:
High and low voltage switch yards, unit 2 turbine building chiller cooling towers, plant service water (PSW) pumps, and residual heat removal service water (RHRSW)pumps on May 20, 2024.
71111.04 - Equipment Alignment
Partial Walkdown Sample (IP Section 03.01) (4 Samples)
The inspectors evaluated system configurations during partial walkdowns of the following systems/trains:
- (1) Unit 2 division 1 residual heat removal (RHR) system on April 15 through 17, 2024
- (2) Main control room environmental control (MCREC) system on April 23, 2024
- (3) Unit 1 high pressure coolant injection (HPCI) system on April 30, 2024
- (4) Unit 1 division 2 PSW while supplying 1B emergency diesel generator (EDG) on May 22, 2024
Complete Walkdown Sample (IP Section 03.02) (1 Sample)
- (1) The inspectors evaluated system configurations during a complete walkdown of the unit 2 reactor core isolation cooling (RCIC) system on May 28, 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) Diesel generator building on April 2, 2024
- (2) Unit 2 reactor building 130' elevation on April 4, 2024
- (3) Unit 1 reactor building 164' and 158' elevations on April 18, 2024
- (4) FLEX storage building on April 23, 2024
- (5) Unit 2 southeast diagonal and HPCI pump room on April 29, 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 the following activities:
- Unit 1 RHR pump in-service test on April 16, 2024
- main condenser inleakage repair on April 16, 2024
- Unit 1 and Unit 2 RPS 'B' channel manual scram functional testing on May 13, 2024
- realigning the Unit 2 drywell (DW) chillers on May 22, 2024
Licensed Operator Requalification Training/Examinations (IP Section 03.02) (1 Sample)
- (1) The inspectors observed and evaluated a crew in the simulator performing scenario, HLT-SG50472-15.5, "Security Threat with LOSP or Loss of Ultimate Heat Sink on April 15, 2024.
71111.12 - Maintenance Effectiveness
Maintenance Effectiveness (IP Section 03.01) (1 Sample)
- (1) Hatch maintenance rule (a)(3) evaluation report, June 20,2023
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) Unit 1 elevated risk due to 1A PSW out of service, on April 2, 2024
- (2) Unit 2 elevated risk due to the division 1 RHR system outage on April 9, 2024
- (3) Unit 2 elevated risk due to swapping from 2B DW chiller to 2A drywell chiller on April 10, 2024
- (4) Unit 1 elevated risk due a RCIC planned system outage on April 30, 3034.
71111.15 - Operability Determinations and Functionality Assessments
Operability Determination or Functionality Assessment (IP Section 03.01) (6 Samples)
The inspectors evaluated the licensee's justifications and actions associated with the following operability determinations and functionality assessments:
- (1) Condition Report (CR) 11065083, 1B RHR pump seal leak reviewed on April 11, 2024
- (2) CR 11049455, Unit 1 RHR drainline broken pipe support in drywell reviewed on April 11, 2024
- (3) CR 11050535, Loose quencher arm support bolts in unit 1 torus reviewed on April 30, 2024
- (4) CR 11070876, Unit 1 and 2 RHRSW pump discharge check valve degradation reviewed on May 16, 2024
- (5) CR 11078112, Unit 1 A loop and B loop core spray (CS) / RHR pump room coolers reviewed on May 30, 2024
- (6) CR 11063068, past operability report of main control room A/C (MCRAC) and main control room environmental control (MCREC) systems with temporary PSW manifold installed, reviewed on June 27, 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) (6 Samples)
(1)34SV-E11-004-2, 2A RHRSW pump check valve on April 26, 2024 (2)34SV-E51-002-1, Unit 1 RCIC on May 04, 2024 (3)34SV-SUV-023-2, Unit 2 jet pump and recirculation flow mismatch operability on May 8, 2024 (4)34SO-P64-001-2, Unit 2 drywell chiller swap from 2B to 2A after repair to 2A drywell chiller on May 22, 2024 (5)34SV-E41-002-2, Unit 2 HPCI operability run after system outage on May 29, 2024 (6)34SV-E41-002-1, Unit 1 HPCI operability run after system outage on May 31, 2024
Surveillance Testing (IP Section 03.01) (4 Samples)
(1)34SV-E51-005-2, Unit 2 RCIC start from remote shutdown panel (RSDP) on April 3, 2024 (2)34SV-E51-002-1, Unit 1 RCIC surveillance on April 4, 2024 (3)34SV-E11-001-1, Unit 1 RHR operability (Division 2) performed on April 16, 2024 (4)34SV-SUV-023-2, Unit 2 jet pump and recirculation flow mismatch operability performed on May 8, 2024
Inservice Testing (IST) (IP Section 03.01) (1 Sample)
(1)34SV-P41-001-1, 1A and 1C PSW pump IST on April 2,
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) Unit 1 (April 1, 2023 through March 31, 2024)
- (2) Unit 2 (April 1, 2023 through March 31, 2024)
BI02: RCS Leak Rate Sample (IP Section 02.11) (2 Samples)
- (1) Unit 1 (April 1, 2023 through March 31, 2024)
- (2) Unit 2 (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) CAR 608270, Equipment reliability checklist for unit 1 feedwater check valves F010A and F032A failing local leak rate testing (LLRT) on February 11, 2024
- (2) CAR 629180, Cause determination for U1 reactor scram due to low suction trip of the
'A' reactor feedwater pump on March 11, 2024.
71152S - Semiannual Trend Problem Identification and Resolution Semiannual Trend Review (Section 03.02)
- (1) The inspectors reviewed the licensees corrective action program to identify potential trends in fire protection program implementation that might be indicative of a more significant safety issue. Specifically, the inspectors reviewed the following issue documented in the CAP:
- CR11032637, cognitive trend NRC identified overfilled trash cans in safety-related areas
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 05000321/2024-001-00, Primary containment penetration exceeded maximum allowable primary containment leakage rate (La) (ADAMS accession No. ML24100A863)
The inspection conclusions associated with this LER are documented in this report under Inspection Results Section 71152A. This LER is closed.
- (2) LER 05000321/2024-002-00 for Edwin I. Hatch Nuclear Plant, Unit 1 Manual Reactor Trip Due to Loss of Feedwater," (ADAMS Accession No. ML25130A268)
The inspection conclusions associated with this LER are documented in this report under Inspection Results Section 71152A. This LER is closed.
- (3) LER 05000366/2024-002-00, Incorrectly Installed Temporary Modification Results in Multiple Conditions Prohibited by Plant Technical Specifications (ADAMS Accession No. ML24115A241)
The inspection conclusions associated with this LER are documented in this report under Inspection Results Section 71111.15. This LER is closed.
- (4) LER 05000321, 05000366/2024-002-01, Incorrectly Installed Temporary Modification Results in Multiple Conditions Prohibited by Plant Technical Specifications (ADAMS Accession No. ML24185A259)
The inspection conclusions associated with this LER are documented in this report under Inspection Results Section 71111.15. This LER is closed.
INSPECTION RESULTS
Inadequate Installation of a Temporary Modification Resulted in Inoperable Control Room Ventilation Subsystems Cornerstone Significance Cross-Cutting Aspect Report Section Barrier Integrity Green NCV 05000321,05000366/2024002-01 Open/Closed
[H.11] -
Challenge the Unknown 71111.15 The inspectors identified a Green finding and associated non-cited violation (NCV) of Unit 1 and Unit 2 Technical Specification (TS) 5.4.1, Procedures, for the failure to install a temporary plant service water (PSW) modification for the main control room environmental control (MCREC) and main control room air conditioning (MCRAC) systems in accordance with written procedures. As a result, the inadequate installation of this temporary modification rendered the B MCRAC subsystem inoperable.
Description:
The inspectors reviewed Licensee Event Reports (LER) 2024-002-00, Incorrectly Installed Temporary Modification Results in a Condition Prohibited by Plant Technical Specifications issued on April 24, 2024 and LER 2024-002-01, Incorrectly Installed Temporary Modification Results in Multiple Conditions Prohibited by Plant Technical Specifications issued on July 3, 2024.
The MCRAC system is designed to provide a controlled environment in the main control room under both normal and accident conditions. Two subsystems provide the required temperature and humidity control to maintain a suitable control room environment. The MCREC system is designed to provide a protected environment to the main control room occupants following an uncontrolled release of radioactivity, hazardous chemicals or smoke.
The safety related function of the MCREC system includes two independent and redundant high efficiency air filtration subsystems for emergency treatment of recirculated air and outside supply air and a control room envelope (CRE) boundary that limits the inleakage of unfiltered air. One air handling unit (AHU) fan is required for each subsystem to assist in the pressurization function to minimize inleakage of potentially contaminated air into the CRE.
Additionally, a MCREC subsystem is considered operable if one AHU fan is operable, and either operating or having its control switch in standby with operable automatic start capability and the associated AHU cooling coils, water cooled condensing units, refrigerant compressors, and associated instrumentation and controls.
Installation of this temporary modification began on January 23, 2024, in accordance with work order (WO) SNC1039107. It was fully installed and implemented on January 30, 2024.
This modification provided a temporary means of supplying shared main control room air conditioning units with Unit 2 PSW while the normal Unit 1 supply and discharge were unavailable for maintenance during the Unit 1 refueling outage. On February 27, 2024, the inspectors identified the temporary modification associated with the PSW discharge piping from the B MCRAC condensing unit was not installed in accordance with licensee procedure 42EN-P41-001-1. Specifically, paragraph 4.1, step 2 stated, Fabricate AND install pipe supports as required to support piping; including temporary support for 1P41-F1247 shown in Sketch 4 in Table 1. The inspectors determined that the temporary support appeared to be fabricated in accordance with the sketch, but it was not installed as required to support the piping. The bolts were not installed through the temporary support bolt holes and instead a rope was used to support the piping. Use of the rope to perform this function is not in accordance with the procedure and was not approved for use through an engineering evaluation.
1P41-F1247 is a water regulating valve located downstream of the B condensing unit for the B MCRAC subsystem. It acts to control plant service water flow to the condensing unit by sensing the condensing units refrigerant pressure through copper tubing. A decrease in refrigerant pressure will cause the valve to close, reducing the PSW flow to the condensing unit. The licensees past operability review (POR) concluded that this valve was improperly supported, so it would be free to move during a design basis earthquake (DBE), which could cause damage to, or break the copper tube refrigerant sensing line. Breaking the sensing line will be sensed as a loss of refrigerant pressure. This would cause the valve to close, stopping PSW flow to the B condensing unit and tripping both the condenser unit (on high compressor discharge pressure) and fan supporting the AHU. According to the licensees analysis of this issue, during the times when only the B MCRAC subsystem was operating, a design basis accident concurrent with a DBE would result in a trip of the B MCRAC subsystem, which would cause the operating MCREC subsystem to trip on low flow. If the standby MCREC subsystem was available, it would auto-start, but would trip on low flow also. In the main control room, these low flow conditions for the MCREC and MCRAC systems would alarm and alert the operators to start any available MCRAC subsystem(s) in accordance with the annunciator response procedures, system operating procedures and abnormal operating procedures. Additionally, certain procedures allow placing the control switches for the MCRAC AHUs to emergency run, which bypasses the low flow fan trip.
Past Operability Review:
A review of the licensees past operability review (POR) determined the following information regarding subsystem operability:
The MCRAC system is governed by TS limiting condition for operation (LCO) 3.7.5.
The A MCRAC subsystem was inoperable:
January 25 at 0416 until February 8 at 0410 (approximately 14 days) due to low refrigerant.
February 13 at 1131 until February 16 at 0452 (approximately 2.7 days) while the 1A critical instrument bus was tagged out for maintenance.
The B MCRAC subsystem was inoperable:
January 30 at 1020, until February 28 at 1441, approximately 29.2 days, due to the inadequate installation of the temporary modification described above.
The C MCRAC subsystem was inoperable:
January 28 at 1432 until 1608 (approximately 1.6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br />) and again from January 31 at 0115 until 0138 (approximately 0.4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br />) to swap the power supply.
February 1 at 0824 until 2147 (approximately 13.4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br />) because the condenser cooling water was tagged out to install the PSW temporary modification.
February 6 at 2350 until February 10 at 1415 (approximately 3.6 days) while the 1B critical instrument bus was tagged out for maintenance.
The MCREC system is governed by TS LCO 3.7.4.
The A MCREC system was inoperable:
January 30 at 1020 until February 8 at 0410 (approximately 9.2 days) when the A and B MCRAC subsystems were inoperable concurrently as described above.
February 13 at 1131 until February 16 at 0452 (approximately 2.7 days) while the 1A critical instrument bus was tagged out for maintenance.
The B MCREC system was inoperable:
January 31 at 0115 unit 0138 (approximately 0.4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br />) due to three inoperable MCRAC subsystems.
February 1 at 0824 until 2147 (approximately 13.4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br />) due to three inoperable MCRAC subsystems.
February 6 at 2350 until February 10 at 1415 (approximately 3.6 days) while the 1B critical instrument bus was tagged out for maintenance.
Technical Specification Compliance:
Unit 1 and Unit 2 share the MCRAC and MCREC subsystems and the units have a common refueling floor. Unit 2 was in Mode 1 during the entire duration of these issues. Unit 1 was in Mode 1 until February 4 at 0008, when it shutdown to Mode 3. Unit 1 entered Mode 4 on February 4 at 0653 and then entered Mode 5 on February 5 at 1211. Unit 1 transitioned back to Mode 4 on February 23 at 1850.
Unit 1 conducted movements of irradiated fuel assemblies in secondary containment and core alterations between February 7 at 2342 and February 9 at 2200 during the Unit 1 refueling outage. Movement of irradiated fuel assemblies in secondary containment occurred in Unit 2 because the units share a common refueling floor.
Based on the plant operating conditions and MCRAC and MCREC operability above, the following conditions prohibited by TS were:
Between February 1 at 0824 and February 1 at 2147, a total time of 13.4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br />, the two MCREC subsystems were inoperable with both units 1 and 2 operating in Mode 1; the units were not placed in Mode 3 within 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> in accordance with TS LCO 3.7.4 Condition E.
Between January 30 at 1020 and February 10 at 1415, a total time of 11.16 days, one MRCEC subsystem was inoperable with Unit 2 operating in Mode 1; Unit 2 was not placed in Mode 3 within 7 days and 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> in accordance with TS LCO 3.7.4 Condition C.
Between February 6 at 2350 and February 8 at 0410, a total time of 28.33 hours3.819444e-4 days <br />0.00917 hours <br />5.456349e-5 weeks <br />1.25565e-5 months <br />, the two MCREC subsystems were inoperable with Unit 2 operating in Mode 1; Unit 2 was not placed in Mode 3 within 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> in accordance with TS LCO 3.7.4 Condition E.
Between February 7 at 2342 and February 8 at 0410, with two MCREC subsystems inoperable, and with irradiated fuel assemblies being moved in the secondary containment and core alterations in progress; units 1 and 2 did not immediately suspend the movement of these fuel assemblies and core alterations in accordance with TS LCO 3.7.4 Condition F.
Between February 7 at 2342 and February 9 at 2200, with one MCREC subsystem inoperable for greater than 7 days, and with irradiated fuel assemblies being moved in the secondary containment and core alterations in progress; units 1 and 2 did not immediately place the operable MCREC subsystem in pressurization mode, or immediately suspend the movement of these fuel assemblies and did not immediately suspend core alterations in accordance with TS LCO 3.7.4 Condition D.
Between January 30 at 1020 and February 10 at 1415, a total time of 11.16 days, two MCRAC subsystems were inoperable with Unit 2 operating in Mode 1; Unit 2 was not placed in Mode 3 within 7 days and 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> in accordance with TS LCO 3.7.5 Condition D.
Between February 7 at 2342 and February 9 at 2200, with two MCRAC subsystems inoperable for greater than 7 days, and with irradiated fuel assemblies being moved in the secondary containment and core alterations in progress; units 1 and 2 did not immediately suspend the movement of these fuel assemblies and did not immediately suspend core alterations in accordance with TS LCO 3.7.5 Condition F.
Between January 25 at 0416 and February 28 at 1441, a total time of 34.43 days, one MCRAC subsystem was inoperable with Unit 2 operating in Mode 1; Unit 2 was not placed in Mode 3 within 30 days and 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> in accordance with TS LCO 3.7.5 Condition D.
Corrective Actions: The temporary modification was removed on February 28, 2024, which restored the operability of the B MCRAC subsystem. Refrigerant was added to the A MCRAC system. Changes to the temporary modification implementation procedure were being evaluated.
Corrective Action References: CR 11054239, TE 1149351, CAR 626453
Performance Assessment:
Performance Deficiency: Failure to install the temporary modification for the MCRAC and MRCEC systems in accordance with licensee procedure 42EN-P41-001-1 was 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 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 temporary modification was not installed properly which impacted the operability of the common unit 1 and unit 2 MCRAC and MCREC subsystems.
Significance: The inspectors assessed the significance of the finding using IMC 0609 Appendix A, The Significance Determination Process (SDP) for Findings At-Power.
Because Unit 1 was in Mode 1 for a portion of the time, and Unit 2 remained in Mode 1 the entire time the PD was applicable, the inspectors assessed the significance of the finding using IMC 0609 Appendix A, The Significance Determination Process for Findings At-Power. The inspectors screened this finding using Exhibit 3, Barrier Integrity Screening Questions of NRCs Inspection Manual Chapter (IMC) 0609, Appendix A. The inspectors determined that the finding should be screened to Green (very low safety significance)because the finding represented a degradation of the radiological barrier function provided for the main control room. The degradation of the barrier function occurred because the finding impacted the operability of the MCREC subsystems which are designed to provide a protected environment to the main control room occupants by treating the air through several filters and pressurizing the MCR envelope to a higher pressure than the surrounding areas.
The MCR envelope or boundary remained operable during this period.
Cross-Cutting Aspect: H.11 - Challenge the Unknown: Individuals stop when faced with uncertain conditions. Risks are evaluated and managed before proceeding. The individuals implementing the temporary modification on the MCRAC and MCREC systems used an unanalyzed rope instead of the proceduralized temporary support structure to support 1P41-F1247 instead of stopping and getting the necessary assistance.
Enforcement:
Violation: Technical Specifications 5.4.1.a, Procedures, required that written procedures shall be established, implemented, and maintained covering the applicable procedures in Regulatory Guide 1.33, Revision 2, Appendix A, February 1978. Regulatory Guide 1.33, Appendix A, Section 9.a required 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.
Safety-related procedure 42EN-P41-001-1, Temporary Header Routing Plant Service Water from MCREC Chillers to Unit 2, was developed to support a temporary modification of the MCREC and MCRAC systems. Paragraph 4.1, step 2 of the procedure stated, Fabricate AND install pipe supports as required to support piping; including temporary support for 1P41-F1247 shown in Sketch 4 in Table 1.
Hatch Unit 1 and 2 TS LCO 3.7.4, Main Control Room Environmental Control (MCREC)
System required two operable MCREC subsystems while the units are in Mode 1, 2, and 3, during movement of irradiated fuel assemblies in the secondary containment, and during core alterations. LCO 3.7.4, Conditions A through F, require actions to restore inoperable subsystem(s), change MODE, and/or suspend core alterations and the movement of irradiated fuel assemblies in the secondary containment depending on whether one or two MCREC subsystems are inoperable.
TS LCO 3.7.5, Control Room Air Conditioning (AC) System, required three operable control room AC subsystems while the units are in Mode 1, 2, and 3, during movement of irradiated fuel assemblies in the secondary containment, and during core alterations. LCO 3.7.5, Conditions A through F, require actions to restore inoperable subsystem(s), change Modes, verify MCR area temperature, and/or suspend core alterations and the movement of irradiated fuel assemblies in the secondary containment depending on whether one or two control room AC subsystems are inoperable.
Contrary to the above, on January 30, 2024, the licensee failed to perform maintenance that affected the performance of safety-related equipment in accordance with written procedures and documented instructions appropriate to the circumstances. Specifically, the licensee failed to adequately install a temporary pipe support for safety-related valve 1P41-F1247 in accordance with documented instructions in procedure 42EN-P41-001-1. As a result, the B MCRAC subsystem was rendered inoperable from January 30 until February 28, 2024. The inoperability of the B MCRAC in conjunction with maintenance activities of the remaining MCRAC/MCREC subsystems resulted in multiple instances where one or two MCREC and MCRAC subsystems were not operable in accordance with TS 3.7.4 and TS 3.7.5. With the MCREC and MCRAC subsystems in an inoperable condition, the licensee failed to perform the actions specified in the applicable conditions of TS 3.7.4 and TS 3.7.5.
Enforcement Action: This violation is being treated as a non-cited violation, consistent with Section 2.3.2 of the Enforcement Policy.
50.9 Violation for Providing an Inaccurate Unit 2 LER 2024-002-00 Cornerstone Severity Cross-Cutting Aspect Report Section Not Applicable Severity Level IV NCV 05000321,05000366/2024002-02 Open/Closed Not Applicable 71111.15 The inspectors identified a Severity Level (SL) IV non-cited violation (NCV) of 10 CFR 50.9, Completeness and Accuracy of Information, for the licensees failure to provide complete and accurate information in all material respects for licensee event report (LER)050366/2024-002-00, Incorrectly Installed Temporary Modification Results in a Condition Prohibited by Plant Technical Specifications, that was submitted on April 24, 2024.
Description:
The inspectors reviewed LER 2024-002-00 and the licensees past operability review (POR) for an issue caused by an improperly installed temporary modification associated with the main control room air conditioning (MCRAC) and main control room environmental control (MCREC) systems. During this review, the inspectors identified discrepancies between the conclusions in the LER and supporting information in the POR.
Specifically, the inspectors questioned the times and durations of when the three MCRAC subsystems were in operation and technical specification (TS) applicability of the MCRAC system to determine when these subsystems were considered in service, out of service, or inoperable.
One example, in the initial POR, included the operability of the A MCRAC subsystem. The original LER 2024-002-00 stated that while the B MCRAC subsystem was inoperable due to the inadequate modification installation, the A MCRAC subsystem was running during this time and that the habitability of the control room envelope was maintained as only one MCREC and one MCRAC subsystem are credited per the accident analysis. The inspectors questioned this statement because the POR documented three different times where the A MCRAC subsystem was inoperable concurrent with the inoperability of the B MCRAC subsystem. The POR also documented that the C MCRAC subsystem was considered operable but not in service for a period of time concurrent with the inoperability of the A and B MCRAC subsystems. This impacted the operability of both MCREC subsystems. The inspectors were concerned that the POR did not accurately capture all the concurrent MCRAC subsystem inoperability periods and that additional TS limiting conditions for operation violations may have existed.
The identification of these additional concurrent inoperability periods of the MCRAC subsystems resulted in a significant increase in the residents original inspection scope to understand how, and under what circumstances, the MCREC subsystems were impacted. The licensee-initiated condition report (CR) 11073356 on May 3, 2024, to reevaluate the POR and revise the LER due to the inspectors questions. The licensee assembled a cross-functional team of operations, engineering, and regulatory affairs staff to conduct a thorough review of this issue. The POR reanalysis identified a total of 12 TS LCO violations that impacted both unit 1 and unit 2, which were reported in revised LER 05000366/2024-002-01 that was submitted to the NRC on July 3, 2024. Because these TS violations were not reported in the original LER, the inspectors concluded that the licensee failed to provide complete and accurate information when LER 2024-002-00 was submitted on April 24, 2024, which impeded the NRCs ability to properly regulate this issue. The technical aspects of this performance deficiency and associated violation assessed under the significant determination process are documented in this inspection report as 05000321,366/2024002-01.
Corrective Actions: The licensee entered this issue in their corrective action program as CR 11073356 to reevaluate the POR and revise the LER. LER 2024-002-01 was submitted to the NRC on July 3, 2024.
Corrective Action References: CR 11073356, corrective action report (CAR) 676623
Performance Assessment:
The inspectors determined this violation was associated with a minor performance deficiency. In the initial version of the POR associated with CR 11054239 and technical evaluation (TE) 1149351, the licensee failed to determine all applicable time frames of MCRAC and MCREC subsystems inoperability that resulted in TS LCO required action completion times being exceeded as required by licensee procedure NMP-AD031-GL01, Past Operability/Functionality Review, section 4.2.7.c. This is minor because the failure is not viewed as a precursor to a significant event, would not lead to a more significant safety concern, nor was it associated with a cornerstone attribute, and it did not adversely affect the associated cornerstone objective.
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: The inspectors determined this violation was a severity level (SL) IV violation because it aligned with examples d.1 and d.9 provided in Section 6.9, Inaccurate and Incomplete Information or Failure to Make a Required Report, of the Enforcement Policy, dated January 12, 2024. Specifically, the violation resulted in a significant increase in the residents original inspection scope (d.1), and the licensee failed to report 11 occurrences of conditions prohibited by TS (d.9) in the original LER submitted on April 24, 2024.
Violation: Title 10 CFR, paragraph 50.9(a), Completeness and accuracy of information, requires, in part, information provided to the Commission by a licensee or information required by statute or by the Commission's regulations, orders, or license conditions to be maintained by the applicant or the licensee shall be complete and accurate in all material respects. 10 CFR 50.73(a), "Reportable Events," requires, in part, that the licensee shall submit an LER for any event of the type described in this paragraph within 60 days after the discovery of the event.
Contrary to the above requirements, on April 24, 2024, the licensee submitted an LER, as required by 10 CFR 50.73, that was not complete and accurate in all material respects.
Specifically, the licensee reported in LER 05000366/2024-002-00 that only one Unit 2 TS LCO 3.7.4 violation occurred. Following the inspectors questions, and the licensee reanalysis, there were a total of 12 TS LCO violations that impacted both unit 1 and unit 2.
This information is material to the NRC because it is used to determine compliance with reportability requirements, and is used in NRC regulatory oversight functions, including licensee performance assessment, and inspection.
Enforcement Action: This violation is being treated as a non-cited violation, consistent with Section 2.3.2 of the Enforcement Policy.
Failure to Develop a Preventive Maintenance Strategy Based on Site Operating Experience Cornerstone Significance Cross-Cutting Aspect Report Section Barrier Integrity Green NCV 05000321/2024002-04 Open/Closed
[P.5] -
Operating Experience 71152A A self-revealed green finding and associated non-cited violation (NCV) of Technical Specification (TS) 3.6.1.1 was identified for failure to maintain primary containment penetration integrity. While conducting planned local leak rate testing (LLRT) of the unit 1 feedwater check valves it was determined that the primary containment leakage rate exceeded the allowable limit defined in 10 CFR 50, Appendix J, Primary Reactor Containment Leakage Testing for Water-Cooled Power Reactors and specified in Technical Specifications 5.5.12.
Description:
Technical Specifications 5.5.12 Primary Containment Leakage Rate Testing Program states in part that the maximum allowable primary containment leakage rate, La, at Pa is 1.2 percent of primary containment air weight per day, and that primary containment overall leakage rate acceptance criterion is less than or equal to 1.0 La (61,103 actual cubic centimeters per minute [accm] or 272,320 standard cubic centimeters per minute [sccm]).
During the first unit startup following testing in accordance with this program, the leakage rate acceptance criteria are less than or equal to 0.60 La (36,661 accm or 163,392 sccm) for the combined Type B and Type C tests, and 0.75 La (45,827 accm or 204,240 sccm) for Type A tests.
On February 11, 2024, with unit 1 shutdown and in Mode 5 for a planned refueling outage, the licensee performed LLRTs for feedwater check valves 1B21-F010A and 1B21-F032A.
The asfound results of the F010A valve was >60,000 accm at 74 psig. The asfound results of the F032A valve was >60,000 accm at 74 psig. The licensee determined these test results represent combined Type B and C leakage of 3,943,052 sccm, exceeding the TS limit of 272,320 sccm. With both valves installed in a single penetration, penetration 1T23-X9A, the asfound results represented a failure to maintain primary containment integrity. The licensee determined the failure of penetration 1T23-X9A, and subsequent failure of primary containment was attributed to primary containment isolation valves 1B21-F010A and 1B21-F032A exceeding 10 CFR 50 Appendix J limits (La). Based on the asleft passing LLRT performed on these valves at the conclusion of the 2022 refueling outage, and the asfound failing LLRT performed during the 2024 refueling outage, the licensee determined operability of the unit 1 primary containment was lost sometime after the 2022 refueling outage and sometime prior to shutdown for the 2024 refueling outage.
On April 9, 2024, the licensee submitted licensee event report (LER) 05000321/2024-001-00, Primary Containment Penetration Exceeded Maximum Allowable Primary Containment Leakage Rate (La) (ADAMS Accession No. ML24100A863). The inspectors reviewed this LER, and the licensees causal product, as documented in corrective action report (CAR)608270. The licensee determined that the valve discs were misaligned which resulted inleakage through the valves exceeding allowable limits. Misalignment of inboard valve F010A was due to the adjustable hinge pin found out of adjustment and a dowel roll pin was not welded in place. Misalignment of outboard valve F032A was due to a sheared torsional spring on the left side and a sheared roll pin on the right side.
The licensees root cause analysis also concluded that the failure resulted from an inadequate maintenance strategy. Maintenance strategy for the F032A was not updated by the strategy owners to account for failure modes such as internal spring and pin wear prior to valve failure. This would have reduced the risk of a penetration failure due to the history of F010A leak rate failures. The current maintenance strategy for the F032A only monitors seat tightness through the performance of biennial leakage rate testing. Trending of LLRT leakage rates will show health of the valve seat, however, it is less than adequate in determining wear to other internal valve components, such as springs, bushings, and pins. The wear to the pin assembly and torsional springs in F032A are failure modes that were not adequately monitored by the current maintenance strategy. Previous LLRT data for the F032A gave no indication of internal degradation to the valve. Licensee performed interviews with past check valve program owners revealed the reason these strategies were not updated was their confidence in the LLRT ability to monitor all failure modes of the valve. The root cause analysis also identified that the failure was due to inadequate risk management, and that a bias to tolerating longstanding performance issues with containment isolating feedwater check valves resulted in effective mitigating measures not being established on the penetration 9A isolation valves. The F010A valve had a history of LLRT failures in 2010, 2012, 2014, and 2022. The F032A valve has a long history of reliable operation and successful LLRT performances. As demonstrated by the repeat failures, actions to eliminate the failures were not developed and implemented.
Section 3.2 of licensee procedure NMP-ES006-001, PM Template Management and PM Organization Guidance requires, in part, that preventive maintenance (PM) template owners develop the significant failure modes, possible indications of degradation, and recommended tasks (PM template tasks) to prevent or minimize the potential of these failures occurring.
Section 3.2 also require, in part, that PM template owners modify PM templates as required as a result of Industry operational experience (OE), site OE, site or fleet causal evaluations, trending of site or fleet component failures and latest revisions to industry templates. Section 4.2 of NMP-ES006-001, also requires, in part, that failure modes shall be added to the PM template.
On April 9, 2024, based upon the preliminary cause and history, the licensee determined evidence existed to demonstrate that the excessive feed water check valve leakage condition existed during the last operating cycle for longer than allowed by TS 3.6.1.1. The condition was reported in accordance with 10 CFR 50. 73(a)(2)(i)(B) as a condition prohibited by Technical Specifications, under 10 CFR50.73(a)(2)(ii)(A) as a seriously degraded condition and under 10 CFR 50.73(a)(2)(v)(C) as a condition that could have prevented the fulfillment of a safety function of structures or systems needed to control the release of radioactive material. The condition was also reported in accordance with 10 CFR 50.72(b)(3)(ii)(A) as a degraded condition. See Event Notification 56959 for additional information.
Corrective Actions: Valve maintenance and a successful asleft LLRT was performed on each feedwater check valve. Adjustable disc hinge pins were installed in the outboard F032A valve. Primary containment was restored to operable status. A design change for these valves will be initiated and presented to the organization for approval and possible implementation. PM templates/valve maintenance strategies will be revised to account for this style of valve used in this application.
Corrective Action References: 42SV-TET-001-1 on 3/14/2024. Root cause report (CAR 608270).
Performance Assessment:
Performance Deficiency: The licensees failure to develop a preventive maintenance strategy based on site operating experience of failed LLRTs in accordance with licensee procedure NMP-ES006-001, PM Template Management and PM Optimization Guidance, section 3.2, was a performance deficiency.
Screening: The inspectors determined the performance deficiency was more than minor because it was associated with the SSC and Barrier Performance 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 containment isolation function of penetration 1T23-X9A was not preserved during the previous operating cycle as evidenced by failed asfound leak rate testing of the feedwater check valves in this penetration.
Significance: The inspectors assessed the significance of the finding using IMC 0609 Appendix H, Containment Integrity SDP. Per IMC 0609 Appendix A, The Significance Determination Process (SDP) for Findings At-Power, Exhibit 3, Section C, "Reactor Containment," Question 1, the inspectors determined the finding represented an actual open pathway in the physical integrity of reactor containment valves and required further evaluation using IMC 0609, Appendix H, "Containment Integrity Significance Determination Process."
Per IMC 0609, Appendix H, Table 4.1, findings related to containment isolation valves in lines connecting to RCS can contribute to an intersystem loss of coolant accident (ISLOCA). An ISLOCA can occur when a low-pressure system is inadvertently exposed to high RCS pressure beyond its capacity. In this case, the feedwater lines have the same pressure rating as the pressure vessel and would not generally contribute to large early release frequency (LERF). Table 7.2, Phase 2 Risk Significance -Type B Findings at Power provides screening guidance for findings of leakage from drywell to environment >100 % containment volume/day through containment penetration seals.
IMC 0308, Attachment 3, Containment Integrity Significance Determination Process Technical Basis, Section 3.03, Type B Findings and Systems That Are of Concern to LERF says a LERF significant leakage rate from containment of 100 percent containment volume/day would correspond to about 200 La for BWR Mark I plants. The asfound leakage rate of 272,320 sccm represents about 14.5 La and therefore is not considered a LERF significant leakage rate from containment, and screens to Green characterization per IMC 0609, Appendix H, Table 7.2 Phase 2 Risk Significance - Type B Findings at Power.
The plant design includes feedwater check valves, which are safety related, automatic valves that are designed to close without operator action following an accident and are considered active devices. The post-accident function of the feedwater check valves is to automatically close in order to provide a reduction of post-accident dose associated with the feedwater line leakage path. The accident sequence related to the finding is not significant to LERF and characterized as Green (very low safety significance).
Cross-Cutting Aspect: P.5 Operating Experience: The organization systematically and effectively collects, evaluates, and implements relevant internal and external operating experience in a timely manner. Specifically, the licensee did not effectively implement internal operating experience of failed LLRT history to modify the PM templates to account for all valve failure modes. Instead, the licensee relied on LLRT testing which was not adequate to detect valve degradation for the outboard tilting disc check valves.
Enforcement:
Violation: Hatch Unit 1 Technical Specification (TS) 3.6.1.1, Primary Containment, requires primary containment shall be operable while the unit is in Modes 1, 2, or 3. With primary containment inoperable due to the failed LLRT of the F010A and F032A feedwater check valves, LCO 3.6.1.1 Condition A required restoration of primary containment to operable status within one hour to meet the LCO. Condition B required the licensee to place the plant in Mode 3 in 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> and Mode 4 in 36 hours4.166667e-4 days <br />0.01 hours <br />5.952381e-5 weeks <br />1.3698e-5 months <br /> if the required actions and associated completion time was not met.
Contrary to this requirement, the asfound LLRT test results of the feedwater check valves F010A and F032A exceeded TS limits and represented a failure to maintain primary containment integrity. Based on the LER submitted by the licensee regarding the issue and inspector evaluation, it was determined that Unit 1 primary containment was inoperable for some period between March 6, 2022, to February 4, 2024, while the Unit was in modes 1, 2 or 3 and actions were not taken to place the plant in Mode 3 in 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> and Mode 4 in 36 hours4.166667e-4 days <br />0.01 hours <br />5.952381e-5 weeks <br />1.3698e-5 months <br />.
Enforcement Action: This violation is being treated as a non-cited violation, consistent with Section 2.3.2 of the Enforcement Policy.
Failure to Assess and Manage Risk of Conducting Maintenance on a Condensate Pump with the Main Condenser under Vacuum Cornerstone Significance Cross-Cutting Aspect Report Section Initiating Events Green NCV 05000321/2024002-03 Open/Closed
[H.12] - Avoid Complacency 71152A A Green self-revealed finding and non-cited violation (NCV) of Title 10 of the Code of Federal Regulations (CFR) 50.65(a)(4) was identified on March 11, 2024, when the licensee failed to adequately assess and manage the risk of isolating the unit 1 B (1B) condensate pump with the main condenser operating with a vacuum. As a result, air entered the condensate and feedwater systems which resulted in the trip of the running A (1A) reactor feed pump (RFP)on low suction pressure and a manual scram of the reactor due to lowering reactor vessel water level.
Description:
On March 11, 2024, unit 1 was operating at approximately 35 percent of rated thermal power (RTP) and conducting power ascension. The 1B condensate pump was secured due to observed degradation, which the licensee determined required an emergent tagout for repairs. During the tagout, air was introduced into the condensate and feedwater systems through leakage of the pumps suction valve when the pump vent and drain valves were opened. This resulted in a trip of the running 1A RFP and a manual scram of the reactor due to lowering water level in the reactor vessel. The reactor core isolation cooling (RCIC)and high-pressure coolant injection (HPCI) systems auto started and injected water into the reactor vessel, as designed. The operators started the B (1B) RFP and lined it up to inject into the reactor vessel within 2 minutes, then secured the RCIC and HPCI injection systems.
Event Notification 57021 was made to the NRC in accordance with 10 CFR 50.72.
The inspectors documented their immediate follow up of the scram in Hatchs first quarter integrated inspection report 05000321,366/2024001, under section 71153.
On May 9, 2024, the licensee submitted licensee event report (LER) 05000321/2024-002-00, Unit 1 Manual Reactor Trip Due to Loss of Feedwater (ADAMS Accession No. ML24130A268). The inspectors reviewed this LER, the licensees scram/transient analysis, and causal product, as documented in corrective action report (CAR) 629180. The licensee determined that a contributing cause of the scram was the failure to evaluate the risk of isolating the 1B condensate pump as required by licensee procedure NMP-DP001, Operational Risk Awareness, Revision 24.3, dated June 24, 2023. Specifically, section 4.7, Emergent Work Risk Assessment and Attachment 10, BWR Red Sheet, required additional reviews and approvals of the work scope and risk mitigation because the work affected the condensate pump (from section 2 of the BWR red sheet) and errors associated with the work could cause a unit trip (scram) or transient (from section 3 of the BWR red sheet). The inspectors concluded that the additional reviews should have directed the isolation of the 1B condensate pump in accordance with section 4.3.34, Isolating a Condensate Pump With Main Condenser Under Vacuum, of the condensate and feedwater operating procedure, 34SO-N21-007-1, Condensate and Feedwater System, Version 52.14.
This procedure section contained methods, from previous operating experience, to evaluate air inleakage and adequacy of the condensate pump suction isolation valve before proceeding further, reducing the likelihood of air intrusion into the condensate system.
Corrective Actions: Following the scram, the licensee replaced the 1B condensate pump and its suction isolation valve, implemented interim measures to require BWR red sheets (emergent work risk assessments) for all emergent work and require reverse briefs focusing on risk before work began. Additional corrective actions associated with the inadequate risk assessment are in progress.
Corrective Action References: Condition reports (CRs) 11058287 and11058294.
Performance Assessment:
Performance Deficiency: The failure to assess and manage the increase in risk associated with the emergent work activity of isolating the 1B condensate pump in accordance with licensee procedure NMP-DP001 was a performance deficiency.
Screening: The inspectors determined the performance deficiency was more than minor because it was associated with the Human Performance attribute of the Initiating Events cornerstone and adversely affected the cornerstone objective to limit the likelihood of events that upset plant stability and challenge critical safety functions during shutdown as well as power operations. Specifically, the performance deficiency led to an event where air entered the condensate and feedwater systems that resulted in the trip of the operating 1A RFP (on low suction pressure) and a manual scram of the unit 1 reactor (i.e., upset plant stability) due to lowering water level in the reactor vessel (i.e., challenge to a critical safety function).
Significance: The inspectors screened this finding using Exhibit 1, Initiating Events Screening Questions of IMC 0609, Appendix A. The finding could not be screen to Green and required a detailed risk evaluation (DRE) because the finding caused a reactor trip and the loss of mitigation equipment (e.g., main feedwater) relied upon to transition the plant from the onset of the trip to a stable shutdown condition. A regional senior reactor analyst (SRA)performed a DRE using the guidance in IMC 0609 Appendix A, SAPHIRE 8 Version 8.2.10, and the Hatch units 1 and 2 Standardized Plant Analysis Risk (SPAR) model Version 8.83.
An event assessment was performed, instead of a condition assessment, because the performance deficiency was related to the inadequate performance of a specific maintenance activity. The dominant accident sequence was a loss of main feedwater (LOMFW) with both the HPCI and RCIC pumps failing to run, and operators failing to manually depressurize the reactor and failing to refill the condensate storage tank. The change in core damage frequency (delta CDF) was less than 1E06, consistent with a finding of very low safety significance (i.e., Green). The following assumptions were made in the DRE:
- The term for a LOMFW initiating event, IELOMFW, was set to true because a LOMFW occurred (i.e., trip of the running 1B RFP). All other initiating events were set to false.
- The high-pressure injection top event was modified to include a recovery term for a single RFP because the restart of a pump is directed by procedure and was performed by the crew (1B RFP) in approximately 2 minutes into the event. The SRA created a term for operator recovery of one RFP per abnormal response procedures, MFW-XHE-REC1MFWPUMP, and set its value to 1E02 using SPAR-H and all nominal performance shaping factors. This term was combined (with an OR logic operator) with a 1B RFP failure-tostart, MFW-TDP-FSPUMPB, to account for the nominal failure-tostart probability of the pump when attempting to recover.
- The term for two or more safety relief valves (SRVs) failing to close, PPR-SRV-OO2VLVS, was set to false because SRVs would not be expected to lift on a reactor trip from 35-percent of RTP due to a LOMFW event.
- The terms for operator failure to depressurize the reactor, ADS-XHE-XMMDEP3, and for operator failure to depressurize the reactor, ADS-XHE-XMNOCRD OPERATOR FAILS TO DEPRESSURIZE REACTOR (CRD UNAVAIL), were adjusted using SPAR-H to account for additional time to diagnose and perform these actions at a lower decay heat loading due to being at 35 instead of 100 percent RPT.
- The delta CDF was approximated by the conditional core damage frequency of the initiating event minus the baseline CDF for the event tree.
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. Specifically, the tagout preparer and operations crew did not thoroughly review or challenge the adequacy of the steps used to isolate the pump in light of actual plant conditions (i.e., main condenser under vacuum) and assumed this was a simple tagout to isolate the 1B condensate pump.
Enforcement:
Violation: 10 CFR 50.65(a)(4) Requirements for Monitoring the Effectiveness of Maintenance at Nuclear Power Plants, states in part, before performing maintenance activities, the licensee shall assess and manage the increase in risk that may result from the proposed maintenance activity.
Contrary to this requirement, on March 11, 2024, the licensee failed to properly assess and manage the risk of isolating the 1B condensate pump while operating unit 1 under a condenser vacuum at 35 percent RTP. Licensee procedure NMP-DP001, "Operational Risk Assessment," sections 4.7 and Attachment 10, if followed properly, would have required additional risk reviews and development of compensatory measures to manage the risk before allowing the work to proceed. This could have prevented the air intrusion into the condensate and feedwater system, the low suction pressure trip of the running 1A RFP, and subsequent manual scram of unit 1 on low reactor vessel water level.
Enforcement Action: This violation is being treated as a non-cited violation, consistent with Section 2.3.2 of the Enforcement Policy.
Minor Violation 71152S NRC Identified Multiple Overfilled Waste Containers Identified in Safety Related Areas Minor Violation: The inspectors identified that the licensee failed to regularly inspect and empty waste containers to prevent them from becoming overfilled as required by section 4.1.5.c of licensee procedure NMP-ES035-014, Fleet Transient Combustible Controls, Rev.
7.0.
The inspectors reviewed condition report (CR)11032637 which was initiated in December 2023 and documented a trend associated with overfilled trash cans with self-extinguishing lids in safety related areas. The licensee initiated a short-term corrective action (crew learning) and a technical evaluation to evaluate potential long term corrective action(s). The crew learning reminded station personnel to read the signs on the waste containers to prevent them from becoming overfilled. The signs stated to not fill the container more than 75% full. Technical Evaluation (TE) 1143483 was created to evaluate the trend, but with a due date of 7/25/2024, the inspectors were not able to assess the adequacy of any additional corrective actions stemming from this TE. During the Unit 1 refueling outage in February through March 2024, the inspectors identified two overfilled waste containers near the drywell control point (continuously manned and/or high traffic area). The inspectors informed nearby plant staff and observed the removal of the trash. On June 28, 2024, three additional full or overfilled waste containers were observed just outside the refueling floor, on the U2 reactor building 185' elevation (the lid did not have the sign to not fill more than 75 percent full), and the U1 130' elevation. Radiation Protection (RP) and Operations staff were informed, and these containers were emptied. The licensee initiated CR11089279.
Screening: The inspectors determined the performance deficiency was minor. The PD did not adversely affect the mitigating systems cornerstone objective because of the relatively low combustible loading of the container's contents and that the containers had intact self-extinguishing lids which act to suppress a fire in the waste container.
Enforcement:
For each of the above examples, the licensee ensured the waste containers were emptied to restore compliance. This failure to comply with Technical Specifications (TS)5.4.1.a, "Procedures" constitutes a minor violation that is not subject to enforcement action in accordance with the NRCs Enforcement Policy. TS 5.4.1.a required in part, written procedures shall be established, implemented, and maintained covering the applicable procedures recommended in RG 1.33, Rev. 2, Appendix A, February 1978. Section 1.l of Appendix A of RG 1.33 requires in part, Plant Fire Protection Program written procedures.
Licensee procedure NMP-ES035-014, Fleet Transient Combustible Controls is an applicable procedure.
EXIT MEETINGS AND DEBRIEFS
The inspectors verified no proprietary information was retained or documented in this report.
- On July 22, 2024, the inspectors presented the integrated inspection results to Matthew Busch and other members of the licensee staff.
DOCUMENTS REVIEWED
Inspection
Procedure
Type
Designation
Description or Title
Revision or
Date
Procedures
DIOPS-56-0293
Hot Weather Operation
2.2
Drawings
D11001
P&ID for service water piping at intake structure sheet no. 1
03/12/2024
Drawings
H11600
P&ID for service water diesel generator sheet 2
01/20/2022
Drawings
H26023
03/25/2015
Drawings
H26024
05/05/2011
Procedures
Residual Heat Removal System
45.5
Procedures
High Pressure Coolant Injection (HPCI) System
30.6
Procedures
Reactor Core Isolation Cooling (RCIC) System
28.10
Procedures
Standby Diesel Service Water System
9.4
Procedures
Control Room Ventilation System
24.0
Fire Plans
NMP-ES035-
019-GL02
Hatch Nuclear Plant Pre-Fire Plan Index
03/04/2024
Fire Plans
NMP-ES035-
019-GL02-F06
Diesel Generator Building El. 130
1.0
Fire Plans
NMP-ES035-
019-GL02-F121
FLEX Storage Building
1.0
Fire Plans
NMP-ES035-
019-GL02-F14
U1 Reactor Building El. 158/164
1.0
Fire Plans
NMP-ES035-
019-GL02-F29
U2 Reactor Building El. Below 130
1.0
Fire Plans
NMP-ES035-
019-GL02-F30
U2 Reactor Building El. 130
1.0
Miscellaneous
HSG50472-15.5
Security Threat with LOSP or Loss of Ultimate Heat Sink
04/15/2024
Procedures
NMP-TR405
Simulator Exercise Guide and Evaluation
2.0
Procedures
NMP-TR416
Licensed Operator Continuing Training Program
Administration
13.2
Corrective Action
Documents
CRs 11086833,
11086876,
11086884
Procedures
NMP-ES027
11.1
Calculations
Hatch U2 R8D
Current Risk Summary Report as of 4/11/2024 10:00
04/11/2024
Inspection
Procedure
Type
Designation
Description or Title
Revision or
Date
Configuration
Risk Monitor
Corrective Action
Documents
Condition Report
(CR) 11066596
Corrective Action
Documents
Resulting from
Inspection
Condition Report
(CR) 11066880
Miscellaneous
Unit 1 Current Risk Summary Report
04/30/2024
Procedures
Complete Loss of Drywell Cooling
2.1
Procedures
Fast Reactor Shutdown
2.2
Procedures
Primary Containment Chilled Water System
14.10
Procedures
NMP-DP001
Operational Risk Awareness (BWR Red Sheet)
04/10/2024
Procedures
NMP-OS010
Protected Train/Division and Protected Equipment Program
10.0
Procedures
NMP-OS010-002
Hatch Protected Equipment Logs
2.6
Corrective Action
Documents
Corrective Action
Documents
CR 11065083,
11049455,
11050296,
11049422,
11050535,
10861710,
11078112
Corrective Action
Documents
Resulting from
Inspection
CRs 11054239,
11073356
Drawings
S50128
MS SRV DISCHARGE LINE QUENCHER - TORUS - TEE
QUENCHER
04/26/2010
Engineering
Evaluations
RER
SNC1737541-01
Evaluations for broken RHR supports identified during 1R31
Engineering
TE 1147603
Inspection
Procedure
Type
Designation
Description or Title
Revision or
Date
Evaluations
Engineering
Evaluations
TE 1149007
Engineering
Evaluations
TE 1154987,
1154988,
1155096,
1155103
Operability
Evaluations
NMP-AD012-F01
Operability Determination Support Basis
05/23/2024
Procedures
SCM-005
Warehouse Operations - Material/Service Receipt Inspection
Report (MSRIR)
03/09/2023
Work Orders
SNC 1093611
Inspect Torus TQuencher Bolts
Work Orders
SNC 1719889
Remove/Replace Snubber 1E11F20H001
2/13/2024
Work Orders
SNC 963414
1E11-F005A, 1A RHRSW pump discharge check valve
inspection
05/01/2022
Work Orders
SNC1804700
Safety related items ordered from unqualified supplier
05/20/2024
Corrective Action
Documents
CR 11064550
Double Indication for 2E51-F523 RCIC Governor Valve
04/03/2024
Corrective Action
Documents
CR 11067951
Corrective Action
Documents
CR 11074599
Indication on 2B21-R611B "Total Recirc Loop B" appears to
be incorrect
05/07/2024
Corrective Action
Documents
CR 11074879
Unit 2 MRatio failed when manual 34SV-SUV-023-2
performed
05/08/2024
Corrective Action
Documents
CR 11074921
Unit 2 jet pump surveillance complete sat
05/08/2024
Corrective Action
Documents
CR 11078231
2A DW Chiller tripped
05/21/2024
Corrective Action
Documents
CR 11078237
Unit 2 Drywell Chiller Water System Supply Temperature
Slightly Unstable
05/21/2024
Corrective Action
Documents
CR11068322
RSDP instrument channel check
Drawings
H27476
Unit 2 Jet Pump Instrumentation System 2B21E Elementary
Diagram, Sheet 2
8.0
Inspection
Procedure
Type
Designation
Description or Title
Revision or
Date
Miscellaneous
NLOGS-2-5-08-
24
Unit 2 Main Control Room logs
05/08/2024
Miscellaneous
NLOGS-2-5-29-
24
Unit 2 Main Control Room Logs
05/29/2024
Procedures
Reactor Recirculation Pump(s) Trip, Or Recirc Loops Flow
Mismatch, Or ASD Power Cell Failure
Procedures
Primary Containment Chilled Water System
14.10
Procedures
RHR Service Water Pump Operability
19.5
Procedures
HPCI Pump Operability
05/31/2024
Procedures
HPCI Pump Operability
05/29/2024
Procedures
RCIC Pump Operability
04/04/2024
Procedures
RCIC Pump Operability
05/04/2024
Procedures
Operation of RCIC From The Remote Shutdown Panel
04/03/2024
Procedures
Plant Service Water Pump Operability
04/02/2024
Procedures
jet pump and recirculation flow mismatch operability
05/08/2024
Procedures
NMP-DP001
Operational Risk Awareness - BWR Red Sheet
5/22/2024
Work Orders
SNC1413918
Check Valve Internal Inspection
04/25/2024
Work Orders
SNC1756315
Double Indication for 2E51-F523 RCIC Governor Valve
04/04/2024
Work Orders
SNC1763110
Coupling Inspection for RHRSW Pump 2E11C001A
04/18/2024
Work Orders
SNC1765376
Vendor to perform repairs 2E11F005A
04/24/2024
Work Orders
SNC1769842ED
Short Form Item Equivalency Evaluation
04/24/2024
Work Orders
SNC1783378
Incorrect indication on 2B21-R611B "Total Recirc Loop B
Flow" appears to be incorrect
05/08/2024
Work Orders
SNC1805953
2A DW chiller tripped. Investigate and repair process board
05/22/2024
71151
Procedures
Reactor Coolant Weekly (Sample Sheets for Unit 1 -
April 2023 through March 2024)
71151
Procedures
Reactor Coolant Weekly (Sample Sheets for Unit 2 -
April 2023 through March 2024)
71152A
Corrective Action
Documents
71152A
Corrective Action
Documents
CR 11049165,
11057636
71152A
Corrective Action
CR 11058287
Inspection
Procedure
Type
Designation
Description or Title
Revision or
Date
Documents
71152A
Engineering
Evaluations
TE 1147460
Cognitive trend - LLRT results
2/13/2024
71152A
Procedures
Condensate & Feedwater System
2.14
71152A
Procedures
NMP-DP001
Operational Risk Awareness
24.3
71152A
Work Orders
SNC 1718232
1B21F032A LLRT test exceeded allowable leakage
2/11/2024
71152S
Procedures
NMP-ES035-014
Fleet Transient Combustible Controls
7.0
Corrective Action
Documents
Corrective Action
Documents
Engineering
Evaluations
TE 1147460
Procedures
Summarized LLRT Test Results
03/14/2024