IR 05000335/2022001
| ML22132A016 | |
| Person / Time | |
|---|---|
| Site: | Saint Lucie  |
| Issue date: | 05/12/2022 |
| From: | David Dumbacher NRC/RGN-II/DRP/RPB3 |
| To: | Coffey B Florida Power & Light Co |
| Hamman J | |
| References | |
| IR 2022001 | |
| Download: ML22132A016 (17) | |
Text
May 12, 2022
SUBJECT:
ST LUCIE UNITS 1 & 2 - INTEGRATED INSPECTION REPORT 05000335/2022001 AND 05000389/2022001
Dear Mr. Coffey:
On March 31, 2022, the U.S. Nuclear Regulatory Commission (NRC) completed an inspection at St Lucie Units 1 & 2. On April 11, 2022, the NRC inspectors discussed the results of this inspection with Mr. Daniel DeBoer, Site Vice President and other members of your staff. The results of this inspection are documented in the enclosed report.
Two findings of very low safety significance (Green) are documented in this report. One of these findings involved a violation of NRC requirements. We are treating this violation as a non-cited violation (NCV) consistent with Section 2.3.2 of the Enforcement Policy.
If you contest the violation or the significance or severity of the violation 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 St Lucie Units 1 & 2.
If you disagree with a cross-cutting aspect assignment or a finding not associated with a regulatory requirement 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 St Lucie Units 1 & 2.
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, Signed by Dumbacher, David on 05/12/22 David E. Dumbacher, Chief Reactor Projects Branch 3 Division of Reactor Projects Docket Nos. 05000335 and 05000389 License Nos. DPR-67 and NPF-16
Enclosure:
As stated
Inspection Report
Docket Numbers: 05000335 and 05000389 License Numbers: DPR-67 and NPF-16 Report Numbers: 05000335/2022001 and 05000389/2022001 Enterprise Identifier: I-2022-001-0029 Licensee: Florida Power & Light Company Facility: St Lucie Units 1 & 2 Location: Jensen Beach, FL 34957 Inspection Dates: January 01, 2022 to March 31, 2022 Inspectors: C. Fontana, Emergency Preparedness Inspector J. Hamman, Senior Project Engineer D. Lanyi, Senior Operations Engineer D. Orr, Senior Resident Inspector S. Roberts, Resident Inspector S. Sanchez, Senior Emergency Preparedness Inspector J. Tornow, Physical Security Inspector J. Walker, Resident Inspector Approved By: David E. Dumbacher, Chief Reactor Projects Branch 3 Division of Reactor Projects Enclosure
SUMMARY The U.S. Nuclear Regulatory Commission (NRC) continued monitoring the licensees performance by conducting an integrated inspection at St Lucie Units 1 & 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 Gas Accumulation Management Program Deficiencies Associated with the 2A Low Pressure Safety Injection Pump Cornerstone Significance Cross-Cutting Report Aspect Section Mitigating Green [P.2] - 71152A Systems NCV 05000389/2022001-01 Evaluation Open/Closed The inspectors identified a Green non-cited violation of Technical Specification 6.8.1.c.,
Procedures and Programs, for the failure to establish surveillance test procedures to adequately verify that emergency core cooling system (ECCS) locations susceptible to gas accumulation are sufficiently filled with water as required by Technical Specification Surveillance Requirement 4.5.2.c.
Unit 1 Manual Reactor Trip due to Insufficient Feedwater Flow to 1A Steam Generator Cornerstone Significance Cross-Cutting Report Aspect Section Initiating Events Green [H.5] - Work 71153 FIN 05000335/2022001-02 Management Open/Closed A self-revealed Green finding was identified when the licensee failed to ensure adequate work planning and supervision associated with replacing the Unit 1 PDIS-11-30D1, pressure differential indicating switch (PDIS) between high pressure feedwater heater 5A and moisture separator reheater 1D. Specifically, the Fix It Now (FIN) team leader failed to follow MA-AA-200, FIN Team Processes, and omitted critical aspects of work order planning and execution which caused an upset to steam generator 1A water level resulting in a manual reactor trip.
Additional Tracking Items None.
PLANT STATUS Unit 1 operated at or near rated thermal power (RTP) for the entire inspection period.
Unit 2 began the inspection period at RTP. On January 6th, 2022, during full length control element assembly (CEA) testing, CEA 27 slipped approximately 13 inches. Florida Power and Light (FPL) was unable to realign CEA 27, and a reactor shutdown to Mode 3 was completed as required by Technical Specifications. The licensee repaired CEA 27 in Mode 5 and Unit 2 was restored to RTP on January 20, 2022 and remained at RTP 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.
REACTOR SAFETY 71111.01 - Adverse Weather Protection 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 cold weather on January 18 - 19, 2022, and January 27 - 28, 2022.
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) 2B component cooling water (CCW) and intake cooling water (ICW) trains while the 2A CCW heat exchanger was out of service (OOS) for an emergent pipe repair on January 6, 2022 (2) 2B, and 2C auxiliary feedwater (AFW) train alignment, while the 2A AFW train was OOS for unplanned maintenance on February 9, 2022 (3) 2A and 2B emergency diesel generators (EDG) and the 2B3 4160 V electrical bus, while the 1B and 2B startup transformers were OOS for maintenance from February 16 - 19, 2022
(4) 2A EDG while the 2B EDG fuel oil transfer pump was OOS for maintenance on February 22, 2022 (5) 1C CCW train while the 1A CCW train was OOS for planned maintenance on March 30, 2022 71111.05 - Fire Protection Fire Area Walkdown and Inspection Sample (IP Section 03.01) (6 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 zones (FZ):
(1) FZ 1, Unit 1 AFW and steam trestle area on February 2, 2022 (2) FZ 57, Unit 1 cable spread room, FZ 56 switchgear room 1A, and FZ 60 switchgear room 1B on February 16, 2022 (3) FZ8 and FZ9, 2A and 2B EDG building on February 22, 2022 (4) FZ 6, Unit 2 AFW and stream trestle area on March 1, 2022 (5) FZ 34, Unit 2 B switchgear and A DC equipment room, FZ 37 Unit 2 A switchgear room, and FZ 52 Unit 2 cable spreading room on March 1 - 2, 2022 (6) FZ 6 and 7, 1A and 1B EDG building on March 22, 2022 71111.06 - Flood Protection Measures Inspection Activities - Internal Flooding (IP Section 03.01) (1 Sample)
The inspectors evaluated internal flooding mitigation protections in the:
(1) Unit 1 emergency core cooling system pump rooms on March 10, 2022 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:
An unplanned power reduction and shutdown of Unit 2 for misaligned CEA 27 on January 6, 2022 Unit 2 startup and power ascension activities following a forced outage to repair CEA 27 on January 20, 2022 Licensed Operator Requalification Training/Examinations (IP Section 03.02) (1 Sample)
(1) The inspectors observed and evaluated a licensed operator continuing training evaluation in the control room simulator on February 14, 2022.
71111.12 - Maintenance Effectiveness
Maintenance Effectiveness (IP Section 03.01) (2 Samples)
The inspectors evaluated the effectiveness of maintenance to ensure the following structures, systems, and components (SSCs) remain capable of performing their intended function:
(1) AR 2411304, RV-4, 2A electrical equipment room roof ventilator breaker tripped and one fan impeller is missing, and, AR 2412455, RV-4 unavailability hours exceeded, reviewed on March 16, 2022 (2) 1A EDG exceeding unavailability criteria evaluation, EVAL-PSL-59-02622, reviewed on March 23, 2022 71111.13 - Maintenance Risk Assessments and Emergent Work Control Risk Assessment and Management Sample (IP Section 03.01) (5 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 2 elevated risk while 2A CCW was OOS to repair a through wall leak on January 6, 2022 (2) Unit 2 elevated risk while 2B low pressure safety injection (LPSI), 2B high pressure safety injection (HPSI), and 2B containment spray (CS) pumps were OOS for planned maintenance from January 25 - 26, 2022 (3) Unit 2 elevated risk while 2A AFW pump was OOS for planned maintenance from February 9 - 10, 2022 (4) Unit 1 and Unit 2 elevated risk while the 1B and 2B startup transformers were OOS for planned maintenance from February 16 - 17, 2022 (5) Unit 1 elevated risk while 2C AFW pump was OOS to support the repair of MV-09-11, 2C feed to 2A steam generator valve, on March 24, 2022 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) AR 2417149, 2A AFW pump discharge SE-09-2 body/bonnet leak, review completed on January 27, 2022 (2) AR 2415062, through-wall leak on I-30"-30, 2A CCW heat exchanger ICW discharge line past operability review, completed on February 11, 2022 (3) AR 2417089, no voltage at 2B EDG loading relay with containment spray actuation signal, review completed on February 11, 2022 (4) AR 2411896, Unit 2 representative core exit thermocouple temperature needs calibration, and AR 2417155, QSPDS channel B saturation margin out of band, review completed on March 14, 2022 (5) AR 2416803, 2C charging pump excessive primary packing leakage, review completed on March 2, 2022
71111.19 - Post-Maintenance Testing Post-Maintenance Test Sample (IP Section 03.01) (6 Samples)
The inspectors evaluated the following post-maintenance testing activities to verify system operability and/or functionality:
(1) WO 40810941, 2A CCW heat exchanger through-wall leak repair on the ICW outlet, reviewed on January 10, 2022 (2) 2-OSP-66.03, CEA Drop Time and Position Indication Functional Tests, for control element drive motor 27 replacement reviewed on January 18, 2022 (3) WOs 40772388 and 40772360, 2C AFW, linkage lube and trip valve spring test reviewed on February 3, 2022 (4) WO 40780980, replace HCV-09-2B, main feedwater isolation valve (MFIV), air supply regulator reviewed on February 24, 2022 (5) WO 40820879, troubleshoot and repair ground on MV-09-11 ,2C AFW to 2A S/G, reviewed on March 25, 2022 (6) WO 40813068, replace 1A CCW pump mechanical seal, reviewed on March 31, 2022 71111.20 - Refueling and Other Outage Activities Refueling/Other Outage Sample (IP Section 03.01) (1 Sample)
(1) The inspectors evaluated forced outage activities from January 6 - 20, 2022 when Unit 2 was shutdown to Mode 5 to replace control element drive motor 27 71111.22 - Surveillance Testing The inspectors evaluated the following surveillance testing activities to verify system operability and/or functionality:
Surveillance Tests (other) (IP Section 03.01) (3 Samples)
(1) 1-OSP-52.01B, Surveillance Test of Degraded Grid Voltage B Train, reviewed on January 12, 2022 (2) 2-OSP-69.25, Engineered Safeguards Relay Test, Train B, reviewed on January 25, 2022 (3) 2-OSP-59.01A, 2A Emergency Diesel Generator Monthly Surveillance, reviewed on February 10, 2022 Inservice Testing (IP Section 03.01) (2 Samples)
(1) 1-OSP-99.08A, A Train Quarterly Non Check Valve Test, Section 4.2, V1403, power operated relief block valve, reviewed on March 8, 2022 (2) 1-OSP-09.01C, 1C Auxiliary Feedwater Pump Code Run, reviewed on March 17, 2022 71114.04 - Emergency Action Level and Emergency Plan Changes Inspection Review (IP Section 02.01-02.03) (1 Sample)
(1) The inspectors evaluated submitted Emergency Action Level, Emergency Plan, and Emergency Plan Implementing Procedure changes during the week of February 7, 2022. This evaluation does not constitute NRC approval.
71114.06 - Drill Evaluation Drill/Training Evolution Observation (IP Section 03.02) (1 Sample)
The inspectors evaluated:
(1) On February 14, 2022, the inspectors evaluated a licensed operator continuing training simulator evaluation that included a partial stuck open reactor coolant system power operated relief valve resulting in an Alert declaration and notification to the Florida State Watch Officer and St Lucie and Martin County Emergency Operations Centers.
71114.07 - Exercise Evaluation - Hostile Action (HA) Event Inspection Review (IP Section 02.01 - 02.11) (1 Sample)
(1) The inspectors evaluated the biennial emergency plan exercise during the week of February 7, 2022. The scenario began with a simulated report from the field that a hostile action was occurring inside the protected area, thus meeting the criteria for declaration of a Site Area Emergency. Subsequently, a simulated explosion occurred in the Unit 2 fuel handling building, causing damage to the spent fuel pool system along with increasing radiation levels inside the building. When effluent radiation levels reached a prescribed threshold, conditions for a General Emergency were met, and the Offsite Response Organizations were able to demonstrate their ability to implement emergency actions.
71114.08 - Exercise Evaluation - Scenario Review Inspection Review (IP Section 02.01 - 02.04) (1 Sample)
(1) The inspectors reviewed and evaluated in-office, the proposed scenario for the biennial emergency plan exercise at least 30 days prior to the day of the exercise.
OTHER ACTIVITIES - BASELINE 71151 - Performance Indicator Verification The inspectors verified licensee performance indicators submittals listed below:
IE01: Unplanned Scrams per 7000 Critical Hours Sample (IP Section 02.01) (2 Samples)
(1) Unit 1 (January 1, 2021 - December 31, 2021)
(2) Unit 2 (January 1, 2021 - December 31, 2021)
IE03: Unplanned Power Changes per 7000 Critical Hours Sample (IP Section 02.02) (2 Samples)
(1) Unit 1 (January 1, 2021 - December 31, 2021)
(2) Unit 2 (January 1, 2021 - December 31, 2021)
IE04: Unplanned Scrams with Complications (USwC) Sample (IP Section 02.03) (2 Samples)
(1) Unit 1 (January 1, 2021 - December 31, 2021)
(2) Unit 2 (January 1, 2021 - December 31, 2021)
EP01: Drill/Exercise Performance (DEP) Sample (IP Section 02.12) (1 Sample)
(1) October 1, 2020, through December 31, 2021 EP02: Emergency Response Organization (ERO) Drill Participation (IP Section 02.13) (1 Sample)
(1) October 1, 2020, through December 31, 2021 EP03: Alert and Notification System (ANS) Reliability Sample (IP Section 02.14) (1 Sample)
(1) October 1, 2020, through December 31, 2021 71152A - Annual Follow-up Problem Identification and Resolution Annual Follow-up of Selected Issues (Section 03.03) (1 Sample)
The inspectors reviewed the licensees implementation of its corrective action program related to the following issues:
(1) AR 2334284, Indications of Airbound 2A LPSI Pump During Code Run; and, AR 2392502, 2A Low Pressure Safety Injection Pump Code Run Failure The inspection results associated with these issues are documented in this report under Inspection Results Section 71152A.
71152S - Semiannual Trend Problem Identification and Resolution Semiannual Trend Review (Section 03.02) (1 Sample)
(1) The inspectors reviewed the licensees corrective action program for potential adverse trends in accident monitoring instrumentation action requests that might be indicative of a more significant safety issue.
71153 - Follow Up of Events and Notices of Enforcement Discretion Event Report (IP Section 03.02) (1 Sample)
The inspectors evaluated the following licensee event reports (LERs):
(1) LER 05000335/2021-001-00, Manual Reactor Trip Due to insufficient Feed Flow to Steam Generators (ADAMS Accession Number ML22035A033). The inspection
conclusions associated with this LER are documented in this report under Inspection Results Section 71153.
OTHER ACTIVITIES - TEMPORARY INSTRUCTIONS, INFREQUENT AND ABNORMAL 92709 - Licensee Strike Contingency Plans Licensee Strike Contingency Plans (1 Sample)
(1) On February 15, 2021, at midnight, the contract between the International Brotherhood of Electrical Workers (IBEW) and Florida Power and Light (FPL) expired.
In preparation, inspectors verified that FPL had established a qualification program to ensure that non-bargaining unit personnel would be properly qualified to assume union positions should a strike or lockout have actually occurred. Inspectors verified that the non-bargaining unit watch standers had completed the qualification requirements and verified that licensed operators had active licenses. Inspectors also verified that the required supply chains would not be interrupted if picket lines were established. Additionally, inspectors were in place to assess actual licensee performance in the area of operations and maintenance should a strike/lockout occur.
A strike/lockout did not occur and both sides came to a verbal agreement on February 15, 2021.
INSPECTION RESULTS Gas Accumulation Management Program Deficiencies Associated with the 2A Low Pressure Safety Injection Pump Cornerstone Significance Cross-Cutting Report Aspect Section Mitigating Green [P.2] - 71152A Systems NCV 05000389/2022001-01 Evaluation Open/Closed The inspectors identified a Green non-cited violation of Technical Specification 6.8.1.c.,
Procedures and Programs, for the failure to establish surveillance test procedures to adequately verify that emergency core cooling system (ECCS) locations susceptible to gas accumulation are sufficiently filled with water as required by Technical Specification Surveillance Requirement 4.5.2.c.
Description: On November 4, 2019, at 2022 hours0.0234 days <br />0.562 hours <br />0.00334 weeks <br />7.69371e-4 months <br />, the 2A LPSI pump was started to perform a quarterly test for the Inservice Test (IST) Program using 2-OSP-03.06A. At 2029 hours0.0235 days <br />0.564 hours <br />0.00335 weeks <br />7.720345e-4 months <br />, the 2A LPSI pump was secured after field operators reported to the Unit 2 control room at 2027 hours0.0235 days <br />0.563 hours <br />0.00335 weeks <br />7.712735e-4 months <br /> that the 2A LPSI pump did not develop any discharge pressure. Unit 2 control room operators noted similar indications prior to securing the 2A LPSI pump. Subsequently, field operators vented 80 seconds of gas from the 2A LPSI pump mechanical seal vent, V3670.
On May 6, 2021, at 1423 hours0.0165 days <br />0.395 hours <br />0.00235 weeks <br />5.414515e-4 months <br />, the 2A LPSI pump was started to again perform a quarterly test using 2-OSP-03.06A. At 1434 hours0.0166 days <br />0.398 hours <br />0.00237 weeks <br />5.45637e-4 months <br />, the 2A LPSI pump was secured due to zero discharge pressure and low motor current. When the 2A LPSI pump was secured, the field operator noted smoke issuing from the mechanical seal area and then water began to issue from the seal area of the pump.
The inspectors noted that for each 2A LPSI pump gas void issue, the Gas Accumulation
Management Program (GAMP) was ineffective in preventing the inoperability of the 2A LPSI pump. Gas had accumulated for each event rendering the 2A LPSI pump inoperable and for the May 6, 2021 event, had required corrective actions to repair and replace the pump mechanical seal. The licensees implementing surveillance procedures for GAMP are in part, ADM-03.10, Gas Accumulation Management Program, and 2-OSP-03.31A, UT Evaluation of A Train ECCS Monitored Locations. The licensee also credits procedures such as 2-OSP-03.06A, 2A Low Pressure Safety Injection Pump Code Run, for the 2A LPSI pump, to detect and document anytime unexpected gas is discovered during venting activities of ECCS and containment spray pump casings. Monitoring points and design limits were established by the licensee in engineering evaluation PSL-ENG-SEMS-09-061, GL 2008-01-Gas Accumulation Acceptance Criteria. PSL-ENG-SEMS-09-061 determined the 2A LPSI pump suction line does not include a final high point in the suction path from the water source to the pump casing, and the pump mechanical seal vent valve, V3670, and venting practices in place can detect gas accumulation. The licensee additionally established a 5% gas void operability limit for the 2A LPSI pump. Gas was periodically monitored at the 2A LPSI pump casing by venting the 2A LPSI pump at V3670 concurrent with the performance of 2-OSP-03.06A, 2A Low Pressure Safety Injection Pump Code Run. Technical Specification Surveillance Requirement (TSSR) 4.5.2.c requires the licensee, in accordance with the Surveillance Frequency Control Program (SFCP), to verify ECCS locations susceptible to gas accumulation are sufficiently filled with water. Additionally, the Technical Specifications Bases Attachment 7 of ADM-25.04, Emergency Core Cooling Systems (ECCS), stated that the SFCP frequency takes into consideration the gradual nature of gas accumulation in the ECCS piping and the adequacy of procedural controls governing system operation.
Prior to the establishment of the GAMP (St Lucies GAMP was established in 2009), and until November 29, 2010, the licensee vented ECCS pumps on a weekly basis using procedure 2-NOP-03.02, HPSI/LPSI Normal Operation. On November 29, 2010, the licensee revised the ECCS pump vent frequency to a monthly interval. The licensee justified the reduction in venting frequency on a sufficient lack of documented gas voids and additionally credited the GAMP which included routine quarterly ultrasonic test (UT) monitoring for unexpected voids at numerous locations throughout the Unit 1 and Unit 2 ECCS. The procedure change was documented in AR 579160, ECCS Pump Venting. On May 12, 2012, the licensee subsequently eliminated monthly ECCS pump venting and credited the GAMP program that utilized UT testing rather than venting to monitor for gas accumulation in the ECCS system. The procedure change evaluation was documented in AR 554250-16. The evaluation additionally stated that the ECCS pumps would continue to be vented after every quarterly test of the ECCS pumps in accordance with the inservice testing program.
The inspectors noted that the procedure change evaluation in AR 554250-16 was inadequately justified for two reasons:
1. TSSR 4.5.2.c requires ECCS locations susceptible to gas accumulation are sufficiently filled with water. The 2A LPSI pump casing is a location susceptible to gas accumulation and PSL-ENG-SEMS-09-061 credited venting actions in place as a method of detection since the 2A LPSI pump suction line does not have a high point vent prior to the pump casing.
2. Venting at V3670 after 2A LPSI pump operation during 2-OSP-03.06A is meaningless to the GAMP purpose because the pump operation would have swept any gas that had accumulated while the 2A LPSI pump was in standby operation for about 92 days. A stated purpose in ADM-03.10, Gas Accumulation Management Program, is to trend gas accumulation in order to assure system operability under all operating conditions when required.
Therefore, the inspectors determined that because the 2A LPSI pump suction line and casing was not being effectively monitored for the purposes of the GAMP, the licensee did not meet the provisions of TS 6.8.1.c which requires that procedures be established, implemented, and maintained to cover surveillance and test activities of safety-related equipment.
Corrective Actions: The November 4, 2019, 2A LPSI pump gas void issue and associated corrective actions were documented in AR 2334284. The licensee subsequently performed GAMP UT to assess gas voids at several monitored locations in the 2A LPSI train. The UT did not identify any gas voids. The licensee re-performed the IST successfully and the 2A LPSI pump operable was declared operable at 0212 hours0.00245 days <br />0.0589 hours <br />3.505291e-4 weeks <br />8.0666e-5 months <br /> on November 5, 2019. The licensee established an adverse condition monitoring plan that frequently vented the 2A LPSI pump at its mechanical seal vent, V3670 until the refueling outage started on February 17, 2020. Subsequent gas at V3670 was not detected. The licensee determined the source of the gas for the November 4, 2019 2A LPSI pump gas voiding event was indeterminate, but the most plausible source was discharge piping replacement that occurred in July 2019 and an inadequate method of filling and venting the 2A LPSI train prior to its return to service.
The May 6, 2021, 2A LPSI pump gas void issue and associated corrective actions were documented in AR 2392502. Corrective actions included: replacing the 2A LPSI mechanical seal: an internal inspection of the 2A LPSI pump suction check valve, V07000; a revision to vent all ECCS pumps prior to inservice testing (this was a change to vent the ECCS pumps prior to inservice testing from venting the ECCS pumps after inservice testing); an adverse condition monitoring program to frequently vent the 2A LPSI pump mechanical seal and frequent UT to assess gas voids at several monitored location in the 2A LPSI train; and, a third-party review of the event to determine if additional corrective actions were warranted.
The licensee and the third-party review determined the source of the gas for the May 6, 2021 2A LPSI pump gas voiding event was indeterminate.
The licensee initiated AR 2424557 to perform an organizational effectiveness investigation (OR) into the issues associated with an inadequate GAMP for the 2A LPSI pump. Corrective actions developed as a result of the OR will be tracked by the licensee in AR 2424557.
Corrective Action References: ARs 2334284, 2392502, and 2424557 Performance Assessment:
Performance Deficiency: The licensees failure to establish adequate surveillance test procedures to verify ECCS locations susceptible to gas accumulation, specifically the 2A LPSI pump suction line and casing, are sufficiently filled with water as required by TSSR 4.5.2.c. was 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 2A low pressure safety injection pump was rendered inoperable and unavailable on November 4, 2019 and May 6, 2021 through May 16, 2021.
Significance: The inspectors assessed the significance of the finding using Appendix A, The Significance Determination Process (SDP) for Findings At-Power. Using Exhibit 2 of Appendix A for evaluation of the impact to the mitigating systems cornerstone, the inspectors
determined that a detailed risk evaluation would be required. Specifically, the gas voids in the 2A LPSI pump resulted in the loss of the Unit 2 A-train LPSI subsystem for longer than the Technical Specification allowed outage time.
A detailed risk evaluation was performed by a regional senior reactor analyst using SAPHIRE Version 8.2.5 and NRC St. Lucie Unit 2 SPAR Model Version 8.59. The conditional analysis included a Bayesian update to the failure likelihood of the Unit 2 LPSI pumps with a 271-day exposure time. In addition, the conditional risk associated with the two failures of the A-train LPSI pump were also included using an exposure time of 94 days. No credit was provided in the analysis for recovery of a failed pump. The dominant cutsets involved: 1) a large break loss of coolant initiating event accompanied by a failure of low-pressure injection mitigating function; and 2) steam generator tube rupture sequences accompanied by failure of low-pressure injection or shutdown cooling functions. The analysis determined that the estimated increase in Core Damage Frequency (CDF) and Large Early Release Frequency (LERF) was less than 1E-06/year for delta-CDF and less than 1E-07/year for delta-LERF, representing a finding of very low safety significance (Green).
Cross-Cutting Aspect: P.2 - Evaluation: The organization thoroughly evaluates issues to ensure that resolutions address causes and extent of conditions commensurate with their safety significance. After the November 4, 2019, gas void issue for the 2A LPSI pump, the licensee failed to identify the GAMP was ineffective in preventing the inoperability of the 2A LPSI pump.
Enforcement:
Violation: St. Lucie Unit 2 Technical Specification 6.8.1.c., stated, in part, that written procedures shall be established, implement, and maintained covering surveillance and test activities of safety-related equipment. TSSR 4.5.2.c., stated, in part, that ECCS locations susceptible to gas accumulation are sufficiently filled with water. PSL-ENG-SEMS-09-061, GL 2008-01 Gas Accumulation Acceptance Criteria, credited venting practices in place to ensure the 2A LPSI pump was sufficiently filled with water. Contrary to the requirements of TSSR 4.5.2.c., on May 12, 2012, the licensee eliminated monthly ECCS pump venting and inappropriately credited GAMP program UT testing for detecting gas accumulation at ECCS pumps. On July 14, 2021, the licensee revised 2-OSP-03.06A, 2A Low Pressure Safety Injection Pump Code Run, and included procedure steps to vent the 2A LPSI pump prior to its operation for the detection of gas accumulation and to ensure the 2A LPSI pump was sufficiently filled with water. From May 12, 2012, until July 14, 2021, the licensee did not ensure the 2A LPSI pump was sufficiently filled with water.
Enforcement Action: This violation is being treated as a non-cited violation, consistent with Section 2.3.2 of the Enforcement Policy.
Unit 1 Manual Reactor Trip due to Insufficient Feedwater Flow to 1A Steam Generator Cornerstone Significance Cross-Cutting Report Aspect Section Initiating Events Green [H.5] - Work 71153 FIN 05000335/2022001-02 Management Open/Closed A self-revealed Green finding was identified when the licensee failed to ensure adequate work planning and supervision associated with replacing the Unit 1 PDIS-11-30D1, pressure differential indicating switch (PDIS) between high pressure feedwater heater 5A and moisture
separator reheater 1D. Specifically, the Fix It Now (FIN) team leader failed to follow MA-AA-200, FIN Team Processes, and omitted critical aspects of work order planning and execution which caused an upset to steam generator 1A water level resulting in a manual reactor trip.
Description: On December 10, 2021, Unit 1 was operating at 100% power. The FIN team was replacing the Unit 1 PDIS-11-30D1 due to a steam leak on the PDIS. The 1D MSR level control valve was on the hand jack to manually maintain 1D MSR level. The PDIS, an electro-mechanical device, was isolated under an equipment clearance order (ECO), but for mechanical isolation only. One technician was responsible for mechanical tubing connections and the other technician was responsible for electrical switch connections. At 1024 hours0.0119 days <br />0.284 hours <br />0.00169 weeks <br />3.89632e-4 months <br />, the lead the technician was handling made inadvertent contact with the metal enclosure. The inadvertent contact with the metal enclosure caused the supply fuse to blow, resulting in a loss of high-pressure feedwater heater level control and a reduction in steam generator feedwater flow. Based on lowering and unrecoverable 1A steam generator water level, the reactor was manually tripped by control room operators.
The inspectors reviewed the root cause evaluation associated with this issue documented in AR 2413519. The licensee determined that the FIN team leader failed to follow procedure MA-AA-200, FIN Team Processes, section 3.5, steps 5, 6 and 7.
MA-AA-200, section 3.5, step 5 required a risk assessment to evaluate the work activities in accordance with procedure WM-AA-100-1000, Work Activity Risk Management, which is used to identify, evaluate, and appropriately manage the overall risk associated with online and outage work activities. WM-AA-100-1000, attachment 1, Section 1.0 step 1, required a high-risk classification for a single point vulnerability that can cause a trip, plant transient or short duration shutdown limiting condition for operation, with high-risk classification requiring a high degree of coordination among departments. WO 40807777 was classified as medium risk which removed the requirements for risk mitigation and compensatory measures.
MA-AA-200, section 3.5, step 6 directed the FIN Team Leader to utilize WM-AA-201, Work Order Identification, Screening, and Validation Process, to evaluate and adequately address the operational impact of FIN work. This procedure, in section 4.1, step 2, utilized a work identification, screening, and validation flow chart, which based on the work not being minor, directed the use of procedure MA-AA-203-1001, Work Order Planning. MA-AA-203-1001 section 4.2, step 6, stated that critical steps in work orders should be identified in accordance with attachment 7, Critical Step Identification of the same procedure, with critical steps being defined as A step or action that, if performed incorrectly, will cause irreversible, intolerable harm to plant equipment, people, or significantly impact plant operation, which includes a plant trip or transient.
Finally, MA-AA-200 section 3.5, step 7, directed the FIN team leader to interface with operations department personnel for authorizing work, protective tagging, clearances, and release of equipment. There were two important items that operations department personnel were not aware of when the work was authorized: 1) that the repair included both an electrical component and mechanical component; and 2) only the mechanical component was included in the ECO. Neither the FIN team leader nor operations department personnel were aware of possible interactions between this circuit and other feedwater heating system control valves.
Corrective Actions: The licensee entered this issue into its corrective action program as AR 2413519. The licensee completed accountability actions for the FIN team leaders failure to follow the work process program. The licensee additionally revised MA-AA-203-1001 and
MA-AA-200 to require FIN senior reactor operator (SRO) or on-shift SRO review and approval of all medium or high-risk FIN or emergent work orders.
Corrective Action References: AR 2413519 Performance Assessment:
Performance Deficiency: The failure of the FIN team leader to follow MA-AA-200, FIN Team Processes, omitting critical aspects of work order planning and execution that caused an upset to steam generator water level resulting in a manual reactor trip, 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 FIN team leader failed to follow the work management process and omitted critical aspects of work order planning and execution which caused an upset to steam generator water level resulting in a manual reactor trip.
Significance: The inspectors assessed the significance of the finding using Appendix A, The Significance Determination Process (SDP) for Findings At-Power. The finding screened to very low safety significance (Green) because it did not cause a reactor trip and the loss of mitigation equipment relied upon to transition the plant from the onset of the trip to a stable shutdown condition (e.g., loss of main condenser or the loss of feedwater).
Cross-Cutting Aspect: H.5 - Work Management: The organization implements a process of planning, controlling, and executing work activities such that nuclear safety is the overriding priority. The work process includes the identification and management of risk commensurate to the work and the need for coordination with different groups or job activities. The FIN team leader failed to follow the FIN work management process omitting critical aspects of work order planning and execution which directly resulted in the human performance error that caused an unnecessary upset to steam generator water level resulting in a plant trip.
Enforcement: Inspectors did not identify a violation of regulatory requirements associated with this finding.
EXIT MEETINGS AND DEBRIEFS The inspectors verified no proprietary information was retained or documented in this report.
On April 20, 2022, the inspectors presented the detailed risk evaluation results for the GAMP deficiencies associated with the 2A LPSI pump inspection results to Mr. Wyatt Godes, Regulatory Affairs Manager and other members of the licensee staff.
On April 11, 2022, the inspectors presented the integrated inspection results to Mr.
Daniel DeBoer, Site Vice President and other members of the licensee staff.
On February 11, 2022, the inspectors presented the Emergency Preparedness Hostile Action Based Exercise Inspection inspection results to Mr. Daniel DeBoer, Site Vice President and other members of the licensee staff.
14