IR 05000387/2024012
| ML24330A017 | |
| Person / Time | |
|---|---|
| Site: | Susquehanna  |
| Issue date: | 11/25/2024 |
| From: | Blake Welling NRC/RGN-I/DORS |
| To: | Berryman B Susquehanna |
| References | |
| EA-24-111 | |
| Download: ML24330A017 (1) | |
Text
November 25, 2024
SUBJECT:
SUSQUEHANNA STEAM ELECTRIC STATION, UNITS 1 AND 2 - FOLLOW-UP TO INSPECTION PROCEDURE 71111.12 INSPECTION REPORT 05000387/2024012 AND 05000388/2024012 AND PRELIMINARY WHITE FINDING AND APPARENT VIOLATION
Dear Brad Berryman:
On October 31, 2024, the U.S. Nuclear Regulatory Commission (NRC) completed an inspection at Susquehanna Steam Electric Station, Units 1 and 2, and discussed the results of this inspection with Derek Jones, Plant Manager, and other members of your staff. The results of this inspection are documented in the enclosed report.
Section 71111.12 of the enclosed report documents a finding with an associated apparent violation that the NRC has preliminarily determined to be White with low-to-moderate safety significance. The finding involved the failure to promptly identify and correct a condition adverse to quality for the 'B' emergency diesel generator. We assessed the significance of the finding using the significance determination process and readily available information. We are considering escalated enforcement for the apparent violation consistent with our Enforcement Policy, which can be found at http://www.nrc.gov/about-nrc/regulatory/enforcement/enforce-pol.html. Because we have not made a final determination, no notice of violation is being issued at this time. Please be aware that further NRC review may prompt us to modify the number and characterization of the apparent violation.
We intend to issue our final significance determination and enforcement decision, in writing, within 90 days from the date of this letter. The NRCs significance determination process is designed to encourage an open dialogue between your staff and the NRC; however, neither the dialogue nor the written information you provide should affect the timeliness of our final determination.
Before we make a final decision, you may choose to communicate your position on the facts and assumptions used to arrive at the finding and assess its significance by either (1) attending and presenting at a regulatory conference or (2) submitting your position in writing. The focus of a regulatory conference is to discuss the significance of the finding. Written responses should reference the inspection report number and enforcement action number associated with this letter in the subject line. Responses related to this apparent violation should include: (a) the reason for the apparent violation or, if contested, the basis for disputing the violation; (b) the corrective steps that have been taken and the results achieved; (c) the corrective steps that will be taken; and (d) the date when full compliance will be achieved. Your response should be sent to the U.S. Nuclear Regulatory Commission, ATTN:
Document Control Desk, Washington, DC 20555-0001 with a copy to the Regional Administrator, Region I, and a copy to the NRC Resident Inspector at Susquehanna Steam Electric Station, Units 1 and 2. Your response may reference or include previously docketed correspondences.
If you request a regulatory conference, it should be held within 40 days of your receipt of this letter. Please provide information you would like us to consider or discuss with you at least 10 days prior to any scheduled conference. If you choose to attend a regulatory conference, it will be open for public observation. If you decide to submit a written response, it should be sent to the NRC within 40 days of your receipt of this letter. If you choose not to request a regulatory conference or submit a written response, you will not be allowed to appeal the NRCs final significance determination.
Please contact Sarah Elkhiamy at 610-337-6196, by phone or other means, within 10 calendar days from the issue date of this letter to notify the NRC of your intentions. If we have not heard from you within 10 days, we will continue with our significance determination and enforcement decision.
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, Blake D. Welling, Director Division of Operating Reactor Safety
Docket Nos. 05000387 and 05000388 License Nos. NPF-14 and NPF-22
Enclosure:
Inspection Report 05000387/2024012 and 05000388/2024012 w/Attachment: Detailed Risk Evaluation
Inspection Report
Docket Numbers:
05000387 and 05000388
License Numbers:
Report Numbers:
05000387/2024012 and 05000388/2024012
Enterprise Identifier: I-2024-012-0019
Licensee:
Susquehanna Nuclear, LLC
Facility:
Susquehanna Steam Electric Station, Units 1 and 2
Location:
769 Salem Blvd., Berwick, PA
Inspection Dates:
April 8, 2024, to October 31, 2024
Inspectors:
J. England, Senior Resident Inspector
E. Brady, Resident Inspector
F. Arner, Senior Reactor Analyst
C. Bickett, Senior Reactor Analyst
S. Haney, Senior Project Engineer
D. McHugh, Reactor Inspector
J. Schussler, Senior Project Engineer
Approved By:
Blake D. Welling, Director
Division of Operating Reactor Safety
SUMMARY
The U.S. Nuclear Regulatory Commission (NRC) continued monitoring the licensees performance by conducting baseline inspection at Susquehanna Steam Electric Station, 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
Failure to Identify and Correct B Emergency Diesel Generator Linear Reactor Degradation Cornerstone Significance Cross-Cutting Aspect Report Section Mitigating Systems Preliminary White AV 05000387,05000388/2024012-01 Closed EA-24-111
[H.5] - Work Management 71111.12 The inspectors documented a self-revealed preliminary White finding and apparent violation of Title 10 of the Code of Federal Regulations (10 CFR) Part 50, Appendix B, Criterion XVI,
"Corrective Action," and Technical Specification (TS) 3.8.1 because the licensee failed to promptly identify and correct a condition adverse to quality associated with the B emergency diesel generator (EDG). Specifically, though maintenance personnel noted degradation in the surface epoxy coating of the linear reactors in the B EDG excitation system in maintenance work orders (WOs) in 2017 and 2022, the licensee neither identified this issue as a condition adverse to quality nor took action to promptly correct the deficiency. As a result, during a surveillance test on April 8, 2024, the B EDG failed to run and was rendered inoperable.
Additional Tracking Items
Type Issue Number Title Report Section Status LER 05000387,05000388/
2024-002-00 LER 2024-002-00 for Susquehanna Steam Electric Station, Units 1 and 2, B Diesel Generator Inoperable Due to Failed Excitation System Linear Reactor 71153 Closed
INSPECTION SCOPES
Inspections were conducted using the appropriate portions of the inspection procedures (IPs) in effect at the beginning of the inspection unless otherwise noted. Currently approved IPs with their attached revision histories are located on the public website at http://www.nrc.gov/reading-rm/doc-collections/insp-manual/inspection-procedure/index.html. Samples were declared complete when the IP requirements most appropriate to the inspection activity were met consistent with Inspection Manual Chapter (IMC) 2515, Light-Water Reactor Inspection Program - Operations Phase. The inspectors reviewed selected procedures and records, observed activities, and interviewed personnel to assess licensee performance and compliance with Commission rules and regulations, license conditions, site procedures, and standards.
REACTOR SAFETY
71111.12 - Maintenance Effectiveness
Maintenance Effectiveness (IP Section 03.01) (1 Sample)
The inspectors evaluated the effectiveness of maintenance to ensure the following structures, systems, and components remain capable of performing their intended function:
- (1) Unit Common 'B' EDG differential current trip during surveillance testing on April 8,
OTHER ACTIVITIES - BASELINE
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) Licensee Event Report (LER) 05000387 and 05000388/2024-002-00, B Diesel Generator Inoperable Due to Failed Excitation System Linear Reactor, Agencywide Documents Access and Management System (ADAMS) Accession No.
ML24260A227: The inspection conclusions associated with this LER are documented in this report under the Inspection Results Section, Preliminary White Apparent Violation. This LER is closed.
INSPECTION RESULTS
Failure to Identify and Correct B Emergency Diesel Generator Linear Reactor Degradation Cornerstone Significance Cross-Cutting Aspect Report Section Mitigating Systems Preliminary White AV 05000387,05000388/2024012-01 Closed EA-24-111
[H.5] - Work Management 71111.12 The inspectors documented a self-revealed preliminary White finding and apparent violation of 10 CFR Part 50, Appendix B, Criterion XVI, "Corrective Action," and TS 3.8.1 because the licensee failed to promptly identify and correct a condition adverse to quality associated with the B EDG. Specifically, though maintenance personnel noted degradation in the surface epoxy coating of the linear reactors in the B EDG excitation system in maintenance work orders (WOs) in 2017 and 2022, the licensee neither identified this issue as a condition adverse to quality nor took action to promptly correct the deficiency. As a result, during a surveillance test on April 8, 2024, the B EDG failed to run and was rendered inoperable.
Description:
The EDGs provide reliable power to safety systems during a loss-of-offsite power. The EDGs are designed to provide sufficient electrical power to simultaneously shutdown both reactors including the loads required to mitigate the effects of a design-basis loss-of-coolant accident on one unit with a complete loss-of-offsite power plus a single failure in an onsite power system. The licensee has five EDGs. There are four EDGs (A, B, C, and D) which can supply emergency power to their respective safety buses on Units 1 and 2 upon loss of normal power to the bus. The fifth EDG (E) can be lined up to replace any of the other EDGs to allow for maintenance and testing without a loss of safety function. Each of the EDGs has a Portec static excitation voltage regulator system, which includes linear reactors, an electrical component consisting of a magnetic coil (inductor). The linear reactors function is to shift the phase of the current to the excitation bridge, which supplies the generator field during operation.
On April 8, 2024, the B EDG tripped on generator differential current during its monthly surveillance test. The differential current trip was caused by a failure of the EDG excitation system C phase linear reactor. This failure of a linear reactor resulted in a loss of the excitation field and prevented the EDG from running and providing emergency power. As a result, the B EDG was declared inoperable. The licensee documented this issue in Condition Report (CR)-2024-05881 and performed an apparent cause analysis. The licensee also sent the failed linear reactor to the vendor for a failure analysis. The vendor determined that the linear reactor failed due to a short circuit in the second layer of the winding. The failure resulted from a turn to turn short from a localized failure of the insulation. The thermal breakdown of the insulation was caused by excessive temperatures over time. The excessive temperatures were the result of the winding current, insulation design, core design, installation orientation, and ambient temperatures. The licensee subsequently identified relay K5 had high contact resistance and sent it out for further analysis. The vendor determined it was reasonable to assume the relay failure could create a phase imbalance on the C phase linear reactor resulting in increased currents and temperatures.
Based on review of licensee procedures, vendor failure analysis, maintenance WOs, operating experience, and Electric Power Research Institute (EPRI) documentation, the inspectors determined that the station had multiple opportunities to identify and correct deficiencies identified during visual inspection of the linear reactors prior to the failure on April 8, 2024.
Maintenance Work Orders
Talen performs a visual inspection of the linear reactors on each EDG as part of a 5-year preventive maintenance task. On August 17, 2017, a maintenance technician completed a visual inspection of the B EDG linear reactors under WO ERPM 2041224. The maintenance technician completed step 6.9 of the WO to inspect linear reactors (in series with potential transformers for lamination separation). The maintenance technician identified some surface epoxy cracking. Station Engineering staff accepted the condition as-is and did not document this issue in the corrective action program. On August 1, 2022, a maintenance technician completed another visual inspection of the B EDG linear reactors per WO 2527627 and identified All components found SAT except for linear reactors. They had slight peeling (enclosed pics). The inspectors noted that peeling is a sign of overheating on the external top varnish. This discrepancy was captured within the WO and accepted by Engineering without documenting the condition adverse to quality in the corrective action program for prompt identification and correction. This acceptance by Engineering did not include any additional actions to assess or monitor the impact of the thermal degradation of the linear reactors such as those actions described in the operating experience section below. Therefore, the inspectors determined the licensees maintenance strategy relative to the EDG excitation system did not prevent the eventual failure of the B EDG.
The inspectors noted that this condition was not limited to the B EDG, as the station found similar results during inspection of the D EDG. The inspectors noted that on July 9, 2015, as documented in WO 1842395, a visual inspection by maintenance technicians identified a small pile of debris underneath A1 linear reactor. Engineering accepted the condition, annotated it in the WO, and did not document the condition adverse to quality in the corrective action program for prompt identification and correction. On August 8, 2020, a maintenance technician completed a visual inspection of the D EDG linear reactors under WO EPRM 2310190. The maintenance technician performed step 6.9 and identified dirt/debris under NC5-3 linear reactor (bag enclosed containing material), evidence of high heat on all 3 linear reactors, a ground wire that had been cut off in the past, and a wire on C that shows signs of heat. This deficiency was documented in the corrective action program as CR-2020-11170. As a result of this visual inspection, corrective maintenance WOs were generated in 2020 to replace the linear reactors in all EDGs.
The inspectors noted multiple issues with procurement and maintenance work scheduling that complicated the stations efforts in replacing EDG linear reactors. The licensee received replacement linear reactors in October 2021. However, the parts were placed on a quality control hold until the licensee could complete a component dedication process. The parts remained on a quality control hold and were not dedicated because there was no demand for parts in the work scheduling process, until early 2024. Due to this part status, and because of work scheduling issues, the station was unaware the linear reactors were onsite until early 2024. The inspectors also noted that the 2020 WO to replace the B EDG linear reactors (plant component work order (PCWO) 2363340-0) was categorized as Priority 5 and not in the original maintenance schedule. The WOs should have been screened as Priority 4 and scheduled within the next appropriate work window. Though the work was incorrectly categorized as Priority 5 instead of Priority 4, the licensee had originally intended replacement of the B EDG linear reactors during the B EDG overhaul in July 2022.
However, the inspectors noted the maintenance WO was not in the original outage scope, was added to the scope, and was subsequently removed from the schedule. The licensee was unable to determine a specific reason for the removal. The procurement issues, work prioritization, and work scheduling errors resulted in the station not performing maintenance to replace the linear reactors on the A, B, C, or D EDGs. The licensee did replace the linear reactors (different engine and model of linear reactors than the other EDGs) on the E EDG in August 2023.
Operating Experience
On February 26, 2010, the NRC issued Information Notice (IN) 2010-04, Diesel Generator Voltage Regulation System Component Due to Latent Manufacturing Defect (ML093340392). This IN described an event at a different station where an EDG tripped on generator differential current due to a failed linear reactor. The IN described corrective actions taken by the affected licensee which included a variety of tests and inspections to identify any reliability issues with the linear reactors. The licensee reviewed the IN and updated preventive maintenance task E1940-02 to include the IN 2010-04 during the visual inspection of the linear reactors and increased the inspection frequency to every 5 years. The inspectors noted this preventive maintenance task incorporated a visual inspection whereas the IN described additional inspection and test attributes, such as surge/megger testing to identify degrading insulation integrity, magnetic component replacement based on service life, thermography of the excitation components, and using a data recorder to capture EDG parameters during start-up, i.e., phase currents.
Lastly, the inspectors noted opportunities for the licensee to apply external operating experience which the licensee captured in the corrective action apparent cause analysis documented in CR-2024-05881. This CR documented multiple operating experience reports related to linear reactor failures at other stations since 1985, which were similar to Susquehannas failure. In particular, this CR referenced operating experience for an event in 2019 relative to a fire caused by an internal fault of a linear reactor. However, the inspectors noted that station procedure LS-115, Operating Experience Program, Section 5.2, requires operating experience to be distributed for information or technical evaluation when the Management Review Committee determines it is relevant to the station. The Management Review Committee did not require any technical evaluations for linear reactor failures identified across the industry.
EPRI Documentation
Within the apparent cause evaluation documented in CR-2024-05881, the licensee cited portions of a 2004 EPRI Report 1011108, Portec (NEI Peebles) Voltage Regulator for Emergency Diesel Generators, and a 2013 EPRI Report 30020000568, Plant Engineering:
Emergency Diesel Generator Excitation System End of Expected Life Guidance. Specifically, the inspectors noted EPRI Report 1011108 described obsolescence issues and stated that though the current failure rate was low, failures of the aged excitation systems was anticipated to increase. The report also recommended that stations have spare components readily available to deal with system failures. Furthermore, EPRI Report 30020000568 noted that excitation system magnetics, i.e., linear reactors, were generally manufactured for 10,000 running hours. This report also determined a cumulative probability of failure for Portec excitation subcomponents due to any failure mode at a nominal 30 percent after 40 years in service. The report stated that the primary mechanism that drives the linear reactor failures is degradation of the insulation on the winding, resulting from electrical and thermal stresses resulting from EDG operation. Furthermore, the report stated that the Portec voltage regulators are particularly vulnerable to failures of the magnetics due to the inherent design of the voltage regulator circuit. The inspectors noted at the time of failure, the B EDG running hours were less than the cited value. However, the B and C phase linear reactors for the B EDG were approximately 48 years old, based on quality assurance acceptance in 1976.
Licensee Procedures
The inspectors noted licensee procedure LS-120, Issue Identification and Screening Process, Revision 15, step 3.1.5, states, in part, a condition adverse to quality is defined as any condition, identified with a quality related function, which is determined to be in conflict with the licensees quality program. The step further provides an example of conditions adverse to quality as deficiencies, deviations, defective material or equipment, and non-conformances. The inspectors determined that degradation and subsequent failure of the C phase linear reactor was a condition adverse to quality, as it resulted in inoperability of the B EDG, a safety-related piece of equipment that supplies emergency power to safety-related buses upon loss of power. Additionally, given the failure of the linear reactor, the B EDG would not have been able to run for its 24-hour probabilistic risk assessment (PRA) mission time.
The inspectors reviewed procedure ER-1001, Component Criticality Classification, and determined that the linear reactors are classified as category 2C non-critical-important and cannot be classified as run-to-maintenance (failure) components. Therefore, as documented above, the inspectors concluded that Talen had multiple opportunities to identify and correct this condition adverse to quality prior to failure. Though the station had indications of degradation on installed linear reactors on multiple EDGs, and the benefit of operating experience related to these components, the inspectors noted that Talen continued to accept the condition as-is and did not implement any additional measures to monitor the degradation until the components could be replaced.
Following the failure of the linear reactor, WO 2720331-5 replaced relays K50C519B (K5) and K60C519B (K6). The relays that were removed from the system were sent to a vendor for further failure analysis. The station noted during troubleshooting following the linear reactor replacement with the normal voltage regulator in service, the system was found to have imbalanced silicon-controlled rectifier firing currents. The vendor performed a failure analysis of the K5 and K6 relays. The vendor noted that the contacts in the K5 relay failed to remain closed consistently. When the K5 contacts are not maintained fully closed, the silicon-controlled rectifier will not fire which would present as a phase imbalance. The vendor further stated that the impact of the phase imbalance on the linear reactors is not fully understood, and it is their belief that the marginal design of the linear reactors created a situation where aged equipment and a phase imbalance led to the eventual failure. The phase imbalance resulted in high current through one of the phases and lower currents through the other two phases. The non-failed B phase linear reactor was also sent to the vendor for analysis.
Testing of the B phase linear reactor, which had a lower current due to the imbalance, needed to be terminated due to exceeding the temperature rating of the insulation when subjected to normal nominal (150 amps) current through the linear reactor. Additionally, the failure analysis of the B phase linear reactor identified similar insulator degradation as the failed unit during disassembly and teardown inspection. The inspectors noted the K5 relay was replaced every 5 years as part of a preventive maintenance strategy and would have been replaced multiple times between 2017 to 2024. Consequently, though a relay contact issue could contribute to the linear reactor failure, the degraded condition presented itself in 2017 during the B EDG visual inspection (WO ERPM 2041224).
Talen subsequently determined that there was evidence that the condition existed for longer than allowed by TS 3.8.1 and reported this event as condition prohibited by TS. Additionally, since redundant EDGs were concurrently inoperable following the last B EDG 24-hour endurance run in January 2024, the condition was also reportable as an event or condition which could have prevented the fulfillment of a safety function (LER 05000387 and 05000388/2024-002-00, B Diesel Generator Inoperable Due to Failed Excitation System Linear Reactor).
Corrective Actions: The station replaced the linear reactors on the B EDG using WO 2363340 on April 19, 2024. Additionally, the normal voltage regulator was replaced using WO 2720331-5 and relays K50C519B and K60C519B were replaced using WO 2720331-5.
The linear reactors on the A, C, and D EDGs are currently scheduled for replacement in the first half of 2025.
Corrective Action References: CR 2024-05881
Performance Assessment:
Performance Deficiency: The inspectors determined that the licensee failed to promptly identify and correct a condition adverse to quality for the B EDG in accordance with 10 CFR Part 50, Appendix B, Criterion XVI, Corrective Action, which resulted in the EDG failing to run during a monthly surveillance test.
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, age-related degradation and subsequent failure of the C phase linear reactor resulted in inoperability of the B EDG, a safety-related piece of equipment that supplies emergency power to safety-related buses upon loss of power.
Significance: The inspectors assessed the significance by using IMC 0609, Appendix A, The Significance Determination Process (SDP) for Findings At-Power, Exhibit 2, Mitigating System Screening Questions, and determined this finding required a detailed risk evaluation because the degraded condition represented a loss of PRA function of one train of a multi-train TS system for greater than its allowed outage time.
Region I Senior Reactor Analysts (SRAs) performed the detailed risk evaluation. The finding was preliminarily determined to be of low-to-moderate safety significance (White), assuming an exposure time of 96 days. See Attachment, B EDG Linear Reactor Failure Detailed Risk Evaluation, for a summary of the preliminary risk determination.
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. Specifically, procurement issues, work prioritization, and work scheduling errors resulted in the station not performing maintenance to replace EDG linear reactors failure and an unplanned B EDG inoperability.
Enforcement:
Violation: 10 CFR Part 50, Appendix B, Criterion XVI, Corrective Action, requires, in part, that measures shall be established to assure that conditions adverse to quality, such as failures, malfunctions, deficiencies, and defective material and equipment, and non-conformances are promptly identified and corrected.
Susquehanna TS 3.8.1, AC Sources-Operating, requires, in part, that four EDGs be operable while in Modes 1, 2, or 3. If one required EDG is determined to be inoperable, it shall be returned to an operable status within 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br />. If not restored to an operable status, the unit shall be shut down and placed 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 />.
Contrary to the above, from August 17, 2017, to April 19, 2024, Susquehanna Steam Electric Station failed to establish measures to assure a condition adverse to quality related to degradation of the B EDG linear reactors was promptly identified and corrected. As a result, the B EDG tripped on generator differential current and was rendered inoperable when the C phase linear reactor failed during a surveillance test on April 8, 2024. Consequently, the B EDG was rendered inoperable prior to April 8, 2024, for a period longer than its TS allowed outage time, and the unit was not shut down and 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 /> and Mode 4 within 36 hours4.166667e-4 days <br />0.01 hours <br />5.952381e-5 weeks <br />1.3698e-5 months <br />.
The disposition of this finding closes LER 05000387 and 05000388/2024-002-00, B Diesel Generator Inoperable Due to Failed Excitation System Linear Reactor.
Enforcement Action: This violation is being treated as an apparent violation pending a final significance (enforcement) determination.
EXIT MEETINGS AND DEBRIEFS
The inspectors verified no proprietary information was retained or documented in this report.
- On October 31, 2024, the inspectors presented the NRC inspection results to Derek Jones, Plant Manager, and other members of the licensee staff.
DOCUMENTS REVIEWED
Inspection
Procedure
Type
Designation
Description or Title
Revision or
Date
Corrective Action
Documents
CR-1239829, CR-
20-11170, CR-
24-05881
Drawings
E107172
Sheet 6C Susquehanna S.E.S. Unit 1 and 2 Schematic
Meter and Relay Diagrams 4.16 KV Diesel Generator B
Revision 11
F105801
Sheet 8702 System Schematic Bridge Chassis
Revision 3
FF105801
Susquehanna S.E.S. System Schematic for Diesel
Generators
Revision 6
Miscellaneous
Supplement to 8004137-FA Evaluation of Relays K5 and
K6
Revision 0
8004137-FA
Failure Analysis of Linear Reactor and Voltage Regulator
Revision 1
8004137-FA
Failure Analysis of Linear Reactor and Voltage Regulator
Revision 2
Procedures
ER-1001
Component Criticality Classification
Revision 5
LS-115
Operating Experience Program
Revision 4
LS-120
Issue Identification and Screening Process
Revision 15
NDAP-00-1912
Scheduling and Coordination of Work
Revision 52
NDAP-QA-1901
Susquehanna Station Work Management Process
Revision 32
NDAP-QA-1901
Susquehanna Station Work Management Process
Revision 26
NDAP-QA-1902
Integrated Risk Management
Revision 49
Work Orders
ERPM 2041224
ERPM 2310190
ERPM 2527627
PCWO 2720331-1
PCWO 2720331-2
PCWO 2720331-3
PCWO 2720331-4
PCWO 2720331-5
PCWO 2747512-0
PCWO 2747512-2
RTPM 1842395
ERPM 2310227
ERPM 2396025
Inspection
Procedure
Type
Designation
Description or Title
Revision or
Date
RTPM 2526810
RTPM 2692986
Work Orders
RTPM 2310190
RTPM 2350726
RTPM 2400204
RTPM 2527627
RTPM 2695676
Susquehanna Steam Electric Station, Units 1 and 2
B Emergency Diesel Generator Linear Reactor Failure
Detailed Risk Evaluation
Conclusion
The SRAs estimated the core damage frequency (CDF) related to the C phase linear reactor
failure associated with the B EDG to be White, a finding of low-to-moderate safety significance.
Based on the best-estimate assumptions discussed below, the SRAs determined the CDF for
this issue to be approximately 8.6E-6/yr (White) for Unit 1 and 7.2E-6/yr (White) for Unit 2.
Background and Exposure Time
The EDGs have a static exciter (excitation transformer arrangement) which is a vector summing
unit, where the excitation power is supplied by the vector sum of a three-phase power
transformer (T1) and the three power current transformers. The T1 power transformer steps
down voltage from 4160 and supplies the no-load excitation requirements. The current flow at
the secondary of T1 is phase-shifted by the linear reactors LR1, LR2, and LR3 so that it lags
voltage at the T1 secondary. The vector sum of the current from T1, when shifted by the linear
reactors, and the secondary current from the power current transformers provide the input to a
rectifier bridge as part of the function of the machine excitation. 2017 and 2022 visual
inspections of these linear reactor components indicated epoxy cracking, discoloration, and
peeling, which are indicative of some degree of thermally accelerated aging effects. This
thermally induced condition is indicative of stress and degradation taking place during operation
of the B ED
- G. As such, in accordance with the Risk Assessment of Operational Events
Handbook, Volume I, Revision 2.02, Section 2.5, the SRAs calculated the exposure as a
runtime failure.
Historic B EDG runtime was reviewed back until January 2, 2024, when the EDG had the
capacity and capability to run for the 24-hour mission time. The EDG completed a series of tests
from January 2 to 3, 2024, including a full load reject and a 24-hour endurance run. Therefore,
the exposure period start will be considered at the conclusion of the testing and will conclude at
the time of the B EDG trip which resulted in approximately 95.7 days. Exposure time accounts
for the repair time. This is a unique case, that in most situations when equipment fails, it is not
restored to its function until repaired and that repair time is accounted for in exposure time.
Susquehanna Units 1 and 2 have a backup E standby EDG, which in this case was swapped in
for the failed B EDG which restored the emergency onsite power function to the B or
Division II buses. That repair period to swap the E in for the B was a nominal 7 hours8.101852e-5 days <br />0.00194 hours <br />1.157407e-5 weeks <br />2.6635e-6 months <br />. This
resulted in the E EDG remaining aligned for Division II backup 4kV power during the entire
duration of the B EDG unavailability window. This also would result in the E EDG no longer
being available to swap in for the A, C, or D EDG if required. The B EDG was repaired and
restored into its normal alignment, and declared operable on April 27, 2024, or around 19 days
after the failure.
The SRAs recognized that while the E EDG was substituted in place for the failed B EDG to
support the Division II bus, it restored capability of providing power to these Unit 1 and 2 buses
on a loss-of-offsite power event. Notwithstanding this, there would still be some risk accruing, as
the normal baseline configuration is for the E EDG to be able to backup any failed EDG after
postulated events. Talen performed a calculation for this configuration assuming the E EDG
was no longer available as a backup for the additional 19 days. Because the safety bus backup
power function was fully restored, there was no common-cause failure (CCF) penalty applied
during this configuration. The SRAs determined that with the safety-related 4kV bus function
fully restored by the E EDG, this appeared to be a reasonable position, and the additional risk
accrued was negligible. Therefore, the assumption of an exposure time of 96 days was
reasonable. Lastly, Unit 1 was in a refueling outage from March 20, 2024, until the failure on
April 8, 2024, or a nominal 19 days over the course of the entire exposure period. While there
were timeframes when the B EDG was not required by the Unit 1 refuel outage mode TSs to
be operable, Unit 2 was online for the duration of the exposure period. Thus, Talen made no
reductions to the exposure time for Unit 1 and treated it as 96 days for both units for the detailed
risk assessment. The SRAs also determined this to be a reasonable assumption where risk
estimates would be bounded.
Assumptions
Credit for Demonstrated EDG Runtime
The SRAs reviewed Talens switchyard design and breaker operation and determined that
adjustments to offsite power nonrecovery probabilities would be appropriate, based on
demonstrated successful B EDG runtime during testing performed over the exposure time. The
SRAs divided the exposure period into three separate run intervals for the analysis. The use of
this approach assumes that the observed failure that occurred on April 8, 2024, would be
consistent with the expected average observation of operation before failure if viewed
probabilistically (i.e., if we considered more than one sample, the EDG would be expected to
run on average, for the duration it ran during performance of its monthly surveillance test prior to
failure). This method essentially provided additional credit for the demonstrated runtime of the
B EDG since January 3, 2024, but also factored the potential challenge of offsite power
recovery given the uncertainty with switchyard battery capacity. Implementing this method
effectively reduced the offsite power nonrecovery probabilities and the assumed reduction in
risk is consistent with previous significance determination process applications.
Susquehanna Standardized Plant Analysis Risk (SPAR) Model Modifications
The SRAs performed some notable modifications to the Susquehanna Unit 2 SPAR model, with
the assistance of Idaho National Laboratories (INL), the SPAR model contractor. The Unit 2
changes were used as a surrogate for Unit 1 as well, given the nature of the similar designs with
any plant differences not resulting in notable differences to the internal event evaluation. This
was proven with the results of Talens evaluation with respect to internal events. INL provided a
working version with some required changes within Susquehanna Unit 2 SPAR, Version 8.82,
TLU2. These changes along with numerous other changes made by the SRA support the
best-estimate assessment of risk:
INL changed the CCF basic event and quantification from rolled up into detailed CCF
events.
The loss-of-offsite power event trees originally queried offsite power recovery in
hours. This was inconsistent with other boiling water reactor SPAR models and
produced non-sensical core damage cutsets with overly conservative risk increases.
SRAs added a second residual heat removal top event to the loss-of-offsite power event
trees to address containment heat removal and late injection scenarios. This was
evaluated and agreed to by INL model experts. This change had the largest impact on
risk.
- The fault trees RHR-C-SS and RHR-D-SS were updated to include dependency on both
emergency service water loops A and B. This would provide additional credit consistent
with the as-built plant.
The E EDG is a swing EDG that operators can substitute in for either the A, B, C, or
D EDGs. It requires operator action to align. The original logic did not appear to reflect
this and required adjustments. This logic was updated for the E EDG capability to
reflect this swing configuration using the Calvert Cliffs SPAR model common swing
station blackout (SBO) EDG logic as a model reference. This logic was added to all the
4kV bus fault trees (Units 1 and 2). The result was that the E was now being
adequately credited during postulated events as a potential substitute for a failed EDG.
Susquehanna has a Blue Max 480V EDG. It is used to power battery chargers to
support the high-pressure coolant injection (HPCI) and reactor core isolation cooling
(RCIC) systems and safety relief valves (SRVs) and has a critical role and high
importance. Following discussions with Talen personnel and reviewing their PRA system
notebooks and core damage cutsets, the Blue Max failure to operate was revised to
8E-2. EPS-XHE-XO-BLUE (failure to align) was revised to 7.5E-2 based on Talens
updated PRA model.
The SRAs updated the loss-of-offsite power initiating event probabilities to reflect the
data provided in report INL/RPT-22-68809, Analysis of Loss of Offsite Power Events -
21 Update.
Failures of suppression pool cooling (SPC) were originally driving risk high. This was
due to failure of SPC motor operated valve power. The SRAs assumed operators would
recognize the loss of power and manually open these motor operator valves. It was also
considered that they would be opened very early in the event to maximize SPC before
power would even be lost. Therefore, operator actions were added in AND gates for the
SPC-A and SPC-B fault trees.
Containment venting and spray pond operator actions failure rates were determined by
the SRAs to be overly conservative high (3E-1) and were all lowered by over an order of
magnitude.
SRAs adjusted the test and maintenance (T&M) terms for the A, B, C, and D EDGs
to 2E-3, and the E EDG to 0.11 to match Talens revised PRA application specific
model. The SRAs agreed that the T&M term is effectively absorbed into the E EDG
term, as during maintenance, the E would be substituted in for the A, B, C, and D
EDGs.
No additional credit for recovery of the EDG was provided in this analysis beyond the
recovery credit provided for emergency power systems in the SPAR model sequences.
Revised FLX-XHE-XE-ELAP to 1E-1 to be consistent with Talens PRA model. This is
reasonable, as operators at Talen have more strategies to choose from (e.g., aligning
the E EDG, aligning Blue Max), and these strategies take approximately 1.5 to 2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br />
each, which could influence the decision-making process.
The diverse and flexible coping strategies (FLEX) generator strategy involves deploying
at least two turbine marine generators (TMGs) and running them in parallel to supply
power to all 4kV safety buses on Units 1 and 2. Therefore, the SRAs set
FLX-XHE-ZM-4802 to IGNORE to allow an AND gate logic. FLX-XHE-XM-480 revised
to 8E-2 to be consistent with Talens model. The TMG failure rates were revised to be
consistent with Pressurized Water Reactor Owners Group (PWROG) data and failure
rates.
house event (HE-SBO) in the P1 event trees that was not included in the SBO flagsets.
HE-SBO added and set to TRUE for the ETF-SBO flag sets. Adjusted
PPR-SRV-OO-1VLV from 9E-2 to 2E-2 based on 2021 failure data, assuming 100 valve
strokes during an event.
Event tree post-processing rules were developed to remove credit for extended loss of
alternating current power (ELAP) FLEX tree transition given A, B, and E EDG failures
with Blue Max, as at least one safety bus would still have power, and therefore operators
would not declare an ELAP and invoke FLEX.
Post processing rules were written to adjust the CCF conditional failure value from CCF
of 5 EDGs to CCF of 4 EDGs for conditional case only if a loss-of-offsite power with
EDG E in T&M in a core damage cutset. This would only be applied when running the
conditional case and cannot be used in an event condition assessment, as it would be
inadvertently applied to both base and conditional case.
Post processing rules were developed to adjust CCF conditional failure value from CCF
of 5 EDGs to CCF of 4 EDGs for conditional case only if a loss-of-offsite power with a
stuck open SRV and a failure of the E EDG with no failure of the Blue Max.
Because of the adjustments to the post-processing rules, the SRAs used the direct solve
feature of the SPAR model, with a change set added for the conditional failure of the B
EDG which required inclusion of EDG B Fail to Run set to TRUE and EPS-DGN-TM-
DGB set to TRUE to support the updated swing EDG E credit.
Contributions from Internal Event Risk
Using the SPAR model modifications discussed above, the SRAs used the direct solve function
of Systems Analysis Programs for Hands-On Evaluation (SAPHIRE) to calculate the risk for the
conditional case, which included the B EDG failure to run for the 96-day exposure time. The
method provided additional credit for the demonstrated runtime of the B EDG since
January 3, 2024, by adding additional hours to offsite power recovery within the SBO
sequences while factoring in uncertainty with switchyard battery capacity. For an exposure time
of 96 days, the internal events contribution to the total increase in CDF was a nominal 2.3E-6/yr
for both Units 1 and 2. This was considered the best-estimate case with a sensitivity using no
adjustments for offsite power recovery time resulting in a nominal 3E-6/yr for the 96-day
exposure.
The dominant core damage sequences for internal events included loss-of-offsite-power
scenarios, failure of the Blue Max generator to operate, failure of the A EDG to run, and E
EDG in T&M with failure to recover an EDG or offsite power.
Contributions from External Events
Seismic, High Winds, and Tornadoes
Using the direct solve feature of SAPHIRE, the SRAs estimated the risk contribution from
seismic, high winds, and tornadoes to be very low for the 96-day exposure, i.e., in the E-8/yr
range. The offsite power recoveries were changed to non-recoverable during these base case
and condition runs.
Fire
The Susquehanna SPAR model does not evaluate fire risk. As such, the SRAs used Talens fire
risk results for this issue. The resultant risk evaluation performed by Talen confirmed that fire
risk dominated the overall risk increase for this issue. Talen made significant changes to the fire
PRA model of record to accomplish this significance determination process and used this in
their application specific model document for their risk evaluation. This included incorporation of
multiple NUREGs, updating fire modeling, and using a consolidated fire and smoke transport
tool. This is a fire modeling tool to further investigate areas where risk was being driven very
high due to significant targets being assumed failed during various scenarios. Talen had initially
run the B EDG failure and provided the model of record results which reflected significant risk
due to fires.
Talen performed many fire PRA refinements. One example was the physical analysis unit 2-5G,
2A201 4kV switchgear room. Talen performed walkdowns and reperformed room heat up
calculations using a conservative approach and used a consolidated fire and smoke transport
tool to obtain more realistic room heat up profile. The model confirmed that for a bounding fire
postulated in the physical analysis unit that the room did not reach critical damage temperature
as it was not credible for a hot gas layer to take out critical targets.
After some of the key fire refinements, a few of the remaining top contributors to delta fire risk
were associated with the Unit 1 Turbine Building lower switchgear room. This had a 11 percent
contribution to delta CDF. This is a physical analysis unit bounding scenario. The top core
damage sequence would be a transient fire in this area, with a failure of extended high-pressure
makeup or loss of feedwater due to the fire. Failure of extended HPCI and RCIC operation due
to CCF of 3 of the 5 EDGs with failure of the control rod drive. The fire would isolate the main
steam isolation valves and take out the main condenser, with subsequent failure of SPC due to
the CCF of 3 out of the 4 EDGs and conditional CCF of the E EDG. Blue Max and the EDG
CCFs would also challenge containment heat removal.
A second dominant fire scenario was associated with a control building equipment room fire.
The core damage sequence would be failure of extended high-pressure makeup including RCIC
and HPCI with CCF of 4 EDGs and the E EDG with subsequent failure of the two FLEX TMGs
and late injection.
The SRAs determined that the methodology appeared appropriate along with refinements of
several of the dominant fire contributors. Talen will consider future further refinements of their
fire model, but at this time the SRAs considered the performed work and analysis to be the best
estimate.
Sensitivity Evaluations
NRC Sensitivity Run: No EDG Runtime Intervals Credited
The SRAs conducted a sensitivity analysis to determine the impact of the application of EDG
runtime intervals on the risk associated with this issue. For this sensitivity, the SRAs performed
a direct solve given the various adjustments mentioned in the SPAR model modifications above.
This was performed without adjusting offsite power nonrecovery probabilities to account for
demonstrated B EDG runtime. Though the risk was only slightly higher if the SRAs did not
consider EDG runtime intervals, this result had inconsequential impact on the overall
conclusions of the analysis. This also would only apply to internal event risk, which was not
dominant. The SRAs determined that crediting demonstrated EDG runtime for this analysis is
representative of the best-estimate risk.
Overall Result
Unit 1
Best Estimate
Sensitivity 1
(no runtime credit)
Internal Events
2.3E-6/yr
3.0E-6/yr
Seismic/High Winds/Tornadoes
E-8/yr
E-8/yr
Fire
6.3E-6/yr
6.3E-6/yr
Total
8.6E-6/yr
9.3E-6/yr
The above is for the 96-day exposure time. Also, the numbers may be considered bounding
given Unit 1 was in an outage for 18 days and fire risk at power would be assumed to dominate
the risk, given many of the loss of high-pressure sequences. Repair time is considered
nonconsequential given E EDG was swapped in for B EDG after the failure.
Unit 2
Best Estimate
Sensitivity 1
(no runtime credit)
Internal Events
2.3E-6/yr
3.0E-6/yr
Seismic/High Winds/Tornadoes
E-8/yr
E-8/yr
Fire
4.9E-6/yr
4.9E-6/yr
Total
7.2E-6/yr
7.9E-6/yr
The repair time is considered nonconsequential given the E was swapped for B ED
the fire risk for Unit 1 is higher than Unit 2 because of main control room abandonment
scenarios, where Unit 1 is supported by Division II power and Unit 2 is supported by Division I
power.
The SRAs estimated the increase in CDF related to the B EDG linear reactor failure to be
8.6E-6/yr for Unit 1 and 7.2E-6/yr, a preliminary White finding with low-to-moderate safety
significance. Note the results include Talens fire estimates with INL and PWROG equipment
failure probabilities, including FLEX, applied in those evaluations.
Contributions from Large Early Release Frequency (LERF)
IMC 0609, Appendix H, Table 5.2, applies LERF factors of 0.3 for high-pressure core damage
accident sequences. These Appendix H LERF factors are considered conservative bounding
values. More recent insights from an NRC Office of Research sponsored study by Energy
Research, Inc. (ERI/NRC-03-04), November 2003, indicates that without reactor coolant system
injection during an SBO, there is a high probability that the reactor coolant system would
subsequently depressurize as a result of either temperature-induced creep rupture of the steam
lines or a stuck open SRV (due to high temperature cycling). Subsequent State of the Art
Reactor Consequence Analysis Project at Peach Bottom Nuclear Power Station (NUREG/CR-
7110) have identified that improved modeling and analysis of anticipated types and sizes of
reactor coolant ruptures, projected containment heating and fuel-coolant interactions, and
operator actions taken to flood containment in accordance with Severe Accident Management
Guidelines, significantly reduce the potential for containment breach and the likelihood of an
LER
- F. Therefore, the above reports indicate a more benign containment response at the time of
vessel breach, in terms of direct containment heating and fuel-coolant interaction-induced
containment failure.
The SRA reviewed Talens assumptions relative to radioactivity release category, sequence
timing, equipment performance, and event tree construction within PA-B-NA-069,
Susquehanna PRA Model Event Tree Notebook and Success, Revision 8. Talens PRA model
includes release category assignments of all Level 2 sequences which provides a more detailed
review in assessing the impact on LER
- F. Additionally, Talens PRA model can quantify the risk
of a post core damage LERF, which essentially builds off core damage and estimates the
likelihood that a large amount of radioactive material reaches the environment soon after the
core damage event. This Level 2 PRA models containment isolation and other systems
designed to manage and mitigate containment over-pressurization leading to containment
failure. Talens PRA quantifies the high-early end-state as a representation of LERF. The SRAs
determined that Talens calculated increase in LERF was reasonable (i.e., within the E-7/yr
region) and therefore the impact to LERF was bounded by the increase in CDF for the failure of
the B EDG.
Talens Risk Evaluation and Technical Analysis
Talens risk evaluation and technical analysis of this finding was documented in PA-B-NA-330,
B Diesel Generator Failure Significance Determination Process (SDP) Risk Assessment and
Application Specific Model (ASM) Document. A few of the SRA observations relative to this
calculation included:
Talen determined that a 96-day exposure time was appropriate. They believe once the
E EDG was substituted for the B EDG with the ability to perform the safety function of
emergency power supply to Division II buses, the repair time risk consideration would
end.
Talen has documented and applied CCF, given the nature of the performance deficiency
and coupling factor.
Talens PRA model of record uses failure probabilities which are not consistent with INL
data for systems such as RCIC, HPCI, and FLEX equipment. Talen used a contractors
report/evaluation to reanalyze the failure rates for these systems. This resulted in failure
to run rates for HPCI and RCIC that were an order of magnitude lower than what INL
uses, and which is applied within the NRC SPAR models.
Talen used 2 out of 3 TMGs as a failure criteria, but the result was very close to what the
SPAR model uses. The SRAs believed the failure rates for installing and operating the
TMGs (human error probabilities) were reasonable and increased from the normal failure
rates for typical 480V generators.
Talen used a higher rate (0.1) for failure to declare an ELAP than what is typically
observed (1E-2). This is technically valid, because operators have to evaluate the
capability of being able to align and use the E EDG to substitute for the other EDGs
upon failure. They also can consider the Blue Max depending on conditions which also
would require additional operator resources.
Talens risk results for an exposure time of 96 days are summarized below.
Susquehanna Unit 1
Case 1: Includes contractor-derived failure probabilities, and FLEX (N+1)
(two FLEX TMGs)
6.2E-6/yr
Case 2: Includes INL/PWROG failure probabilities (higher), and FLEX
(N+1)
7.2E-6/yr
Case 3: Includes contractor-derived failure probabilities, and three FLEX
TMGs
4.8E-6/yr
Susquehanna Unit 2
Case 1: Includes contractor-derived failure probabilities, and FLEX (N+1)
(two FLEX TMGs)
5.5E-6/yr
Case 2: Includes INL/PWROG failure probabilities (higher), and FLEX
(N+1)
5.8E-6/yr
Case 3: Includes contractor-derived failure probabilities, and three FLEX
TMGs
4.0E-6/yr
Talens top cutset for internal events is a grid-centered loss-of-offsite power, CCF of the four
EDGs, conditional CCF of the E EDG, SBO, failure to align the FLEX EDGs, and failure to
recover offsite power.
Talenss top core damage cutset for fire is a Unit 1 Reactor Building Division I switchgear room,
with this conditional failure of the B EDG, and failure to initiate containment venting.
References
SAPHIRE, Version 8.2.11
Susquehanna SPAR Unit 2 Model, Version 8.82 (TLU2)
NUREG-2225, Basis for the Treatment of Potential Common-Cause Failure in the
Significance Determination Process, September 2018
EDG and AC Systems PRA notebook, PA-B-NA-087, Revision 1
Risk Assessment of Operational Events Handbook, Volume I, Revision 2.02
DC-FLEX-010, 4160 VAC Connection to E DG and ESS Busses, Revision 9
EC-RISK-0090 (PA-B-NA-330), B Diesel Generator Failure Significance Determination
Process (SDP) Risk Assessment and Application Specific Model (ASM) Document, SSES