IR 05000339/2024090
| ML24330A016 | |
| Person / Time | |
|---|---|
| Site: | North Anna  |
| Issue date: | 12/11/2024 |
| From: | Laura Dudes NRC/RGN-II/DORS |
| To: | Carr E Dominion Energy |
| References | |
| EA-24-126, IR 05000339/2024090 | |
| Download: ML24330A016 (1) | |
Text
SUBJECT:
NORTH ANNA POWER STATION, UNIT 2 - FINAL SIGNIFICANCE DETERMINATION OF A WHITE FINDING AND NOTICE OF VIOLATION AND ASSESSMENT FOLLOWUP LETTER; NRC INSPECTION REPORT 05000339/2024090
Dear Eric Carr:
The U.S. Nuclear Regulatory Commission (NRC) completed its final significance determination of the preliminary White finding discussed with Lisa Hilbert and other members of the Dominion Energy (Dominion) staff during an inspection exit meeting on November 18, 2024. The finding involved the failure to prescribe documented instructions appropriate to the circumstances for foreign material control prior to the assembly and installation of a relay in the Unit 2 J (2J)
emergency diesel generator (EDG) system in January 2022, which resulted in the 2J EDG inoperability.
Following the exit meeting, the NRC staff was informed that Dominion did not contest the characterization of this finding as White and its associated violation as described in the exit meeting. In addition, Dominion declined the opportunity to discuss this issue in a regulatory conference or to provide a written response before the NRC made a final decision, and understood that NRC Inspection Manual Chapter 0609, Attachment 2 appeal rights only apply to those licensees that have either attended a regulatory conference or submitted a written response to a preliminary determination letter.
After considering the information developed during the inspection, the NRC has concluded that the finding is appropriately characterized as White. The NRC has also determined that the failure to prescribe documented instructions appropriate to the circumstances for foreign material control was a violation of Title 10 of the Code of Federal Regulations (10 CFR) Part 50, Appendix B, Criterion V, Instructions, Procedures, and Drawings, as cited in Enclosure 1, Notice of Violation (Notice). The circumstances surrounding the violation and the basis for the significance determination are described in the enclosed inspection report (Enclosure 2). In accordance with the NRC Enforcement Policy, the Notice is considered an escalated enforcement action because it is associated with a White finding.
December 11, 2024 Dominion is required to respond to this enforcement action and should follow the instructions specified in Enclosure 1 when preparing the response. While the appeal rights for the characterization of the finding as White do not apply in this case, Dominion still has the opportunity to contest the violation and provide additional information that the NRC should consider with respect to the enforcement aspects of this case. The NRC review of Dominions response to the Notice will also determine whether further enforcement action is necessary to ensure compliance with regulatory requirements.
The NRC has determined that the performance at North Anna Power Station, Unit 2 would be in the Regulatory Response Column of the Reactor Oversight Process Action Matrix beginning in the fourth quarter of 2024 (October 1, 2024). Therefore, the NRC plans to conduct a supplemental inspection in accordance with Inspection Procedure (IP) 95001, Supplemental Inspection for One or Two White Inputs in a Strategic Performance Area. This IP is conducted to provide assurance that the root and contributing causes for the performance issues are understood, and to provide assurance that the corrective actions are sufficient to address the root and contributing causes and prevent recurrence. This letter supplements, but does not supersede, the annual assessment letter issued on February 28, 2024 (ADAMS Accession Number ML24053A267).
In accordance with 10 CFR 2.390 of the NRCs Rules of Practice and Procedure, a copy of this letter, its enclosures, and your response, will be made available electronically for public inspection in the NRC Public Document Room or from the NRCs document system (ADAMS),
accessible from the NRC Web site at http://www.nrc.gov/reading-rm/adams.html.
If Dominion has any questions concerning this matter, please contact Laura Pearson of my staff at 404-997-4601.
Sincerely, Laura A. Dudes Regional Administrator Docket No.: 05000339 License No.: NPF-7
Enclosures:
1.
Inspection Results w/Attachment
Inspection Report
Docket Number:
05000339
License Number:
NPF7
Report Number:
Enterprise Identifier:
I-2024-090-0011
Licensee: Dominion Energy
Facility: North Anna Power Station, Unit 2
Location: Mineral, VA
Inspection Dates:
April 18, 2024, to November 18, 2024
Inspectors:
K. Carrington, Senior Resident Inspector
Approved By: James B. Baptist, Chief
Projects Branch 4
Division of Operating Reactor Safety
SUMMARY
The U.S. Nuclear Regulatory Commission (NRC) continued monitoring the licensees
performance by conducting an NRC inspection at North Anna Power Station, Unit 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 Prescribe Instructions Appropriate for Installation of Unit 2 'J' Emergency Diesel
Generator Relay
Cornerstone
Significance
Cross-Cutting
Aspect
Report
Section
Mitigating
Systems
White
Open
[H.13] -
Consistent
Process
A White (low-to-moderate safety significance) finding and an associated Violation of 10 CFR 50, Appendix B, Criterion V, Instructions, Procedures, and Drawings, was self-revealed
when the Unit 2 'J' (2J) emergency diesel generator (EDG) experienced a loss of excitation,
on April 18, 2024. Specifically, the licensee failed to prescribe documented instructions
appropriate to the circumstances for foreign material control prior to the assembly and
installation of a relay in the Unit 2 J (2J) emergency diesel generator (EDG) system in
January 2022, which resulted in the 2J EDG inoperability for greater than its Technical
Specification (TS) allowed outage time of 14 days.
Additional Tracking Items
None
INSPECTION SCOPES
Inspections were conducted using the appropriate portions of the inspection procedures (IPs) in
effect at the beginning of the inspection unless otherwise noted. Currently approved IPs with
their attached revision histories are located on the public website at
http://www.nrc.gov/readingrm/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.
INSPECTION RESULTS
Failure to Prescribe Instructions Appropriate for Installation of Unit 2 'J' Emergency Diesel
Generator Relay
Cornerstone
Significance
Cross-Cutting
Aspect
Report
Section
Mitigating
Systems
White
Open
[H.13] -
Consistent
Process
A White (low-to-moderate safety significance) finding and an associated Violation of 10 CFR 50, Appendix B, Criterion V, Instructions, Procedures, and Drawings, was self-revealed
when the Unit 2 'J' (2J) emergency diesel generator (EDG) experienced a loss of excitation,
on April 18, 2024. Specifically, the licensee failed to prescribe documented instructions
appropriate to the circumstances for foreign material control prior to the assembly and
installation of a relay in the Unit 2 J (2J) emergency diesel generator (EDG) system in
January 2022, which resulted in the 2J EDG inoperability for greater than its Technical
Specification (TS) allowed outage time of 14 days.
Description: On April 18, 2024, at 1300, the 2 'J' EDG was started for surveillance testing in
accordance with 2-PT-82.2B, "2J Diesel Generator Test (Simulated Loss of Off-Site
Power). Prior to loading the diesel to its emergency bus, a loss of generator field alarm was
received locally in the field, signaling a loss of voltage and excitation. The diesel was
subsequently secured and declared inoperable in accordance with TS Limiting Condition of
Operation (LCO) 3.8.1, "A.C. Sources - Operating."
Licensee troubleshooting and investigation identified that the K1 (shutdown and generator
field flash) relay failed. Upon disassembly, a plastic piece of foreign material was found
lodged between the relay contacts. This plastic piece of material (source unknown but
presumed to be from packaging) prevented the relay from operating as required. The relay
was replaced, and the diesel was satisfactorily tested and restored to an operable status on
April 19, 2024, at 2351.
The K1 latching relay consists of two relay subcomponents (K1R and K1M). Because the K1
relay comes in two parts, the relay must be assembled prior to installation. On January 13,
2022, the licensee replaced the K1 relay under WO59102493866, "K1/K2/K3/K4 Relay
Replacement PM." The process for relay replacement consisted of each subcomponent
undergoing its own receipt inspection in a warehouse onsite. Through interviews and
document reviews, the inspectors learned that these receipt inspections were nonintrusive in
order to minimize damage to the K1 relay subcomponents or the introduction of foreign
material. Moreover, the primary focus of the receipt inspections entailed verification of
component labels and identification numbers.
After being receipt inspected and transferred to the shop for assembly, the new latching unit
was bench tested, inspected, and installed in the field. The K1 relay bench testing and
assembly was performed in accordance with maintenance procedure 0-EPM-0702-04,
Inspection of EDG K Relay. The inspectors noted that this procedure allowed an
opportunity for visual inspection of old relays intended for reuse in the plant; this inspection
included looking for damage, cracks, burns, wear, relay binding, and ensuring relay
cleanliness. However, the inspectors noted there were no instructions in the maintenance
procedure for performing an inspection of the new relay prior to bench testing, assembly, or
installation. According to inspector interviews, at the time of assembly, it was expected craft
practice to perform a visual inspection of new relays.
Additionally, as a general practice, the licensee expected its employees to exercise foreign
material exclusion controls in accordance with Dominion procedure MA-AA-102, "Foreign
Material Exclusion," however, during their review of WO59102493866, the inspectors noted
there were no details on what the foreign material controls entailed.
The inspectors determined the licensee failed to have adequate documented instructions for
foreign material control prior to the assembly and installation of the relay, following its
replacement in January 2022, which allowed foreign material to remain lodged between the
relay contacts.
Corrective Actions: The licensee replaced the Unit 2 'J' EDG K1 relay, reperformed 2-PT-
82.2B, performed a common mode failure evaluation of the 2 'H' EDG, and restored the
diesel to an operable status. Additionally, the licensee performed an inspection of the same
relay on other diesels, revised its electrical maintenance procedure, 0-EPM-0702-04, and
completed a root cause evaluation.
Corrective Action References: CR1256999
Performance Assessment:
Performance Deficiency: The licensees failure to prescribe documented instructions
appropriate to the circumstances for foreign material control prior to the assembly and
installation of a relay in the Unit 2 J (2J) emergency diesel generator (EDG) system in
January 2022, was a performance deficiency.
Screening: The inspectors determined the performance deficiency was more than minor
because it was associated with the Procedure Quality 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, failure of the K1 relay rendered the 2J EDG inoperable and
incapable of performing its specified safety function.
Significance: The inspectors assessed the significance of the finding using IMC 0609
Appendix AProperty "Inspection Manual Chapter" (as page type) with input value "NRC Inspection Manual 0609</br></br>Appendix A" contains invalid characters or is incomplete and therefore can cause unexpected results during a query or annotation process., The Significance Determination Process (SDP) for Findings At-Power. The
inspectors answered yes to question 3, since the degraded condition represented a loss of
PRA function of one train of a multi-train Technical Specification (TS) system for greater than
the TS-allowed outage time of 14 days and determined a detailed risk evaluation was
warranted. Using the North Anna SPAR model Versions 8.80 (dated 05/26/2022), the initial
probability of core damage frequency was determined to be 1.9E-6/yr which is exceeds the
1E-7/yr threshold for a Green issue. The SRA performed a detailed risk evaluation (DRE)
using the North Anna SPAR model version 8.82 when this model became available (see
attachment).
A regional senior reactor analyst (SRA) conducted a detailed risk assessment the degraded
condition. The details of the detailed risk assessment can be found in the attachment. The
SRA assumed an exposure time of 2236 hours0.0259 days <br />0.621 hours <br />0.0037 weeks <br />8.50798e-4 months <br />. The SRA used SAPHIRE 8 version 8.2.11
and the North Anna SPAR model version 8.82 dated 9/26/2023.
The representative case was determined to be the EPS-DGN-FS-DG1J; DIESEL
GENERATOR 1J FAILS TO START set to TRUE, with N+1 FLEX Credit applied using
change set -FLEX-CREDIT; ELAP DECLARED AND FLEX EQUIPMENT CREDITED and
change set-FLEX-N+1, ELAP DECLARED AND N+1 FLEX EDG CREDITED and for Unit 2
and EPS-DGN-FS-DG2J; DIESEL GENERATOR 2J FAILS TO START set to TRUE, with
N+1 FLEX Credit applied using change set -FLEX-CREDIT; ELAP DECLARED AND FLEX
EQUIPMENT CREDITED and change set FLEX-N+1, ELAP DECLARED AND N+1 FLEX
EDG CREDITED for Unit 1. The FLX-XHE-XL-RECOSP, OPERATOR FAILS TO RESTORE
OFFSITE POWER FOLLOWING FLEX OPERATION (ELAP) basic event was also adjusted
to reflect plant procedures being available for recovery from FLEX power line ups. The
dominate accident sequence was a dual unit Weather Related Loss of Offsite power with a
failure of the 2H EDG, Failure of the SBO EDG, Failure of the FLEX RCS Make up pumps,
and failure to recover offsite power or the 2H EDG in 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> for internal events and a fire in
the emergency switchgear room for external events.
Characterization of this issue is low to moderate safety significance (WHITE) due to change
in core damage frequency being between approximately 5.12 and 7.31 E-6 for Unit 2 and
very low safety significance (GREEN) due to change in core damage frequency being less
than 1E-6 for Unit 1.
Cross-Cutting Aspect: H.13-Consistent Process: Individuals use a consistent, systematic
approach to make decisions. Risk insights are incorporated as appropriate. Specifically, the
licensees process for implementing foreign material controls of the K1 relay were not well-
defined or consistent.
Enforcement:
Violation: Title 10 of the Code of Federal Regulations (10 CFR) 50, Appendix B, Criterion V,
Instructions, Procedures, and Drawings, states, in part, that activities affecting quality shall
be prescribed by documented instructions, procedures, or drawings, of a type appropriate to
the circumstances and shall be accomplished in accordance with these instructions,
procedures, or drawings.
The licensees Nuclear Facility Quality Assurance Program Description, DOM-QA-1, Revision
37, Section 2.7.1, states, in part, that Dominion Energy establish appropriate cleanliness
controls for work on safety-related equipment to minimize introduction of foreign material and
maintain system/component cleanliness throughout maintenance or modification activities,
including documented verification of absence of foreign material prior to system closure.
Procedure 0-EPM-0702-04, Inspection of EDG K Relays and Contacts, is the governing
procedure whose purpose is to provide instructions for inspection and repair of EDG K relays
and contacts.
North Anna TS LCO 3.0.1 requires, in part, that LCOs shall be met during the modes of
applicability. TS LCO 3.8.1, AC Sources, requires, in part, two operable EDG sets capable
of supplying the onsite Class 1E distribution systems; and one EDG capable of supplying the
onsite Class 1E AC distribution system on the other unit for each required shared component
while in Modes 1, 2, 3, and 4.
Contrary to the above, on January 13, 2022, the licensee failed to prescribe appropriate work
instructions for an activity affecting the quality of the safety-related 2J EDG system.
Specifically, licensee procedures 0-EPM-0702-04, Inspection of K Relays and Contacts did
not provide instructions appropriate to the circumstances for maintaining foreign material
controls during the assembly and installation of the K1 relay on the 2J EDG, which resulted in
the failure to identify foreign material obstructing the relay contacts and rendered the 2J EDG
inoperable from January 18, 2024, to April 19, 2024. As a result of the 2J EDGs
inoperability, the licensee failed to meet the operability requirements in TS LCOs 3.0.1 and
3.8.1 for two operable emergency diesel generators on Unit 2 and a diesel capable of
supplying shared components on Unit 1 while in MODE 1. Once the EDG inoperability was
identified on April 18, 2024, the licensee took appropriate corrective actions to restore EDG
operability within the completion times established in TS 3.8.1.
EXIT MEETINGS AND DEBRIEFS
The inspectors verified no proprietary information was retained or documented in this report.
On November 18, 2024, the inspectors presented the NRC inspection results to Lisa
Hilbert, Site Vice President, and other members of the licensee staff.
Attachment
Basis for Significance Determination
PERFORMANCE DEFICIENCY (PD)
The inspectors determined the licensees failure to prescribe documented instructions
appropriate to the circumstances for foreign material controls prior for the 2J emergency diesel
generator (EDG) K1 relay was a performance deficiency. As a result, implementation of the
instructions resulted in installation of a relay with foreign material that affected relay operation
and rendered the EDG inoperable.
SCREENING
Initial SDP Screening:
The inspectors determined the performance deficiency was more than minor because it was
associated with the Procedure Quality 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,
failure of the K1 relay rendered the 2J EDG inoperable and incapable of performing its specified
safety function.
The inspectors assessed the significance of the finding using the Mitigating Systems
Cornerstone Screening Questions in Exhibit 2 of IMC 0609, Appendix A. The inspectors
answered yes to question 3, since the degraded condition represented a loss of Probabilistic
Risk Assessment (PRA) function of one train of a multi-train TS system for greater than the TS-
allowed outage time of 14 days and determined a detailed risk evaluation was warranted.
EXPOSURE TIME
January 18 - April 19, 2024
The failure mechanism of the K1 relay was identified as a piece of foreign material that was
discovered lodged between the relay contacts and precluded its operation. Prior to its failure,
the relay was last replaced in January 2022. This condition is presumed to have existed since
the replacement of the relay in 2022. Since that time, the 2J EDG was successfully run a total of
24 times for surveillance testing. Therefore, one can assume an exposure start time from the
last successful run of the EDG on January 18, 2024, until the 2J EDG relay failure on April 18,
2024, plus the EDG repair time of 1 day. Based on this, the exposure time is 2238 hours0.0259 days <br />0.622 hours <br />0.0037 weeks <br />8.51559e-4 months <br />.
RASP Manual Volume 1 section 2.3 Exposure Time = t + Repair Time
- T = t + Repair Time. For a failure that was determined to have occurred when the component
was last functionally operated in a test or unplanned demand (e.g., failure occurred when the
component was being secured), the exposure time (T) is equal to the total time from the last
successful operation to the unsuccessful operation (t) plus repair time.
- This exposure time determination approach is appropriate for standby or periodically operated
components that fail due to a degradation mechanism that is not gradually affecting the
component during the standby time period.
Influential Assumptions:
1) The failure of the 2J EDG impacts risk for both Unit 2 and Unit 1.
2) Since the North Anna SPAR model only models Unit 1, the 2J EDG was surrogated
by using the 1J EDG when determining the risk for Unit 2 and the 2J EDG was used
when determining the risk for Unit 1.
3) The foreign material was present in the K-1 assembly since installation in January
2022, but it was only able to move when the relay mechanically changed state and
shook the relay housing. Following the successful surveillance run of the 2J EDG on
January 18, 2024, the foreign material migrated to the K1 relay contactors. Thus, the
entire standby period T is used.
4) North Anna does not have any procedural guidance to cross connect the Unit 1 EDGs
to Unit 2 busses and vice versa. Additionally, some of the breakers on
Unit 2 which were present in the SPAR model drawings, which could allow busses to
be cross connected were removed or modified during modifications to the Unit 2, unit
auxiliary transformer/start-up transformer (UAT/SUT) fast bus transfer circuit. Thus,
the SPAR model basic events to cross connect the 1H to 2J and 2H to 2J bus (which
default to True) cannot be adjusted for recovery.
5) Recovery of the 2J EDG was not considered reasonable since the foreign material
could only be found following removal and disassemble of the K1 relay. Recovery of
a second EDG failure and/or offsite power was credited by the SPAR model.
6) Since the foreign material was believed to be packing material, it was likely
introduced during unpacking of the received equipment at North Anna or during
packing by the vendor. In either case, this introduces a common cause failure
mechanism thus common cause failure of all EDGs must be considered. This is the
dominant risk driver for Unit 1 in this case.
7) The North Anna SPAR model does not contain any fire event sequences, and the
licensee does not have a peer reviewed Regulatory Guide (RG) 1.200 compliant
PRA. However, the licensee has a draft fire PRA it is developing for a future
application for 10 CFR 50.69. While this model has not been peer reviewed, the SRA
walked down the plant fire areas and reviewed the Fire PRA model and determined
that this model could be considered best available information. Fire Risk results were
the dominant risk contributor, particularly a fire in the emergency switchgear room
which does not have adequate train separation.
8) The SRA walked down the licensees FLEX implementation strategies, loss of offsite
power (LOOP) procedures and Station Blackout (SBO) procedures. The SRA
identified that North Anna FLEX strategy involves staging and connecting a 120 V
FLEX DG immediately and using this DG to supply vital battery load still in service
following the Deep Load Shed direct by ELAP procedures. This action would extend
battery life to greater than 8 hours9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br />. Thus, if the credited 480 VAC FLEX EDGs failed,
adequate time would be available to deploy and connect the N+1 FLEX EDG. The
120V FLEX DG is not modelled in the SPAR model, but the N+1 EDG is.
9) The SRA walked down the SBO EDG and the procedures for placing this EDG in
service. The SBO EDG automatically starts on a LOOP and repowers the SBO
building and lighting and the breaker controls to align the SBO EDG are located on a
single panel, making this evolution more reliable than most plants.
10) The SRA noted that several of the dominant accident sequences were sequence 17-
03-02 which is a Station Blackout with ELAP declared and all Flex Equipment
successful, but power not recovered in 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br />. This sequence was present for all
four Loss of Offsite Power Events. Since there is sufficient fuel and redundant FLEX
equipment on site and the FLEX strategy would call for SAFER equipment to be
deployed to the site within 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br />, non-recovery of onsite or offsite power alone
would not cause a loss of long-term cooling function. Only operator error when
restoring from FLEX would result in a loss of long-term cooling and failure of the top
event. Reviewing cutsets and fault trees the SRA identified FLX-XHE-XL-RECOSP,
OPERATOR FAILS TO RESTORE OFFSITE POWER FOLLOWING FLEX
OPERATION (ELAP) was a sensitive term in this sequence. The SRA noted the
SPAR-H Analysis assumed there were no procedures. Thus, the SRA adjusted the
basic event by changing the performance shaping factor for procedures in both
diagnosis and Action from not available to nominal. This changed the human error
probability (HEP) from 1.25E-1 to 2.6E-3. This impacts both the 24-hour and 72-hour
power recovery top events.
REPRESENTATIVE CASE CCDP
The SRA used SAPHIRE 8 version 8.2.11 and the North Anna SPAR model version 8.82
dated 9/26/2023.
The representative case was determined to be the EPS-DGN-FS-DG1J; DIESEL
GENERATOR 1J FAILS TO START set to TRUE, with N+1 FLEX Credit applied using
change set -FLEX-CREDIT; ELAP DECLARED AND FLEX EQUIPMENT CREDITED and
change set-FLEX-N+1, ELAP DECLARED AND N+1 FLEX EDG CREDITED and for Unit 2
and EPS-DGN-FS-DG2J; DIESEL GENERATOR 2J FAILS TO START set to TRUE, with
N+1 FLEX Credit applied using change set -FLEX-CREDIT; ELAP DECLARED AND FLEX
EQUIPMENT CREDITED and change set FLEX-N+1, ELAP DECLARED AND N+1 FLEX
EDG CREDITED for Unit 1. The FLX-XHE-XL-RECOSP, OPERATOR FAILS TO RESTORE
OFFSITE POWER FOLLOWING FLEX OPERATION (ELAP) basic event was also adjusted
as discussed above for both units.
Case
Internal
Events (IE)
Fire
Other
External
Events
Total
Representative
Case U2
2.064E-6
3.96E-6
2.714E-7
6.295E-6
Representative
Case U1
6.704E-7
N/A
8.348E-8
7.539E-7
Note 1: The 2J EDG is not credited for any Unit 1 Fire/Safe shutdown strategies.
The dominant accident sequence is a dual unit Weather Related Loss of Offsite power with a
failure of the 2H EDG, Failure of the SBO EDG, Failure of the FLEX RCS Make up pumps,
and failure to recover offsite power or the 2H EDG in 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />.
Uncertainty Analysis:
The SRA ran a Monte Carlo analysis for the Internal Events Representative Case. See
below.
Uncertainty Plot:
I Importance Distribution
5%
Median
Point
Estimate
Mean
95%
Seed
Sample
Size
Method
4.082E-
1.508E-
2.064E-6
2.283E-
6.637E-
12345
3825
Monte
Carlo
Event Tree Dominant Results
Only items contributing at least 1.0% to the total conditional core damage probability (CCDP)
are displayed.
Event Tree
CDP
Description
LOOPWR
1.157E-6
4.282E-8
1.114E-6
(WEATHER RELATED)
LOOPSC
4.460E-7
1.570E-8
4.303E-7
(SWITCHYARD CENTERED)
LOOPPC
2.998E-7
1.101E-8
2.888E-7
(PLANT CENTERED)
LOOPGR
2.383E-7
7.300E-9
2.310E-7
LOSS OF OFFSITE POWER (GRID
RELATED)
Total
2.337E-6
2.726E-7
2.064E-6
Sensitivity Evaluations:
Sensitivity Evaluations:
1) A sensitivity was done for FLEX Credit. North Annas FLEX strategy involves the
deployment of a 120 V generator to supply vital loads on the battery. Then the
480VAC FLEX generators are deployed. The 120V generator increases
available time to deploy the 480 VAC FLEX EDGs from 4 hour4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> to 8 hours9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br /> giving
adequate time to deploy the N+1 EDG. Sensitivities were run for No FLEX
credit, nominal FLEX Credit, for N+1 EDG FLEX Credit), and for Crediting the
FLEX PHASE 3 SAFER equipment. (Note: the FLX-XHE-XL-RECOSP
adjustment is not included in these sensitivities.)
2) Since the Licensee model was used for Fire Events is not a peer reviewed RG 1.200 compliant PRA model, the licensee performed several sensitivities for their
Fire PRA results, including adjusting model truncation, not crediting operator
actions, and not considering common cause failures of the EDG. These
sensitivities are reflected in the risk range reported in the final results and Table
7-1 below.
3) Sensitivities were also run in an attempt to replicate the licensees results for
internal events in order to understand modelling differences. The SRA ran the
following:
a.
Treating the K-1 relay failure as a Failure to load run vice failure to start
(FTS).
b.
Setting the Failure to start to 1.0 vice true (IE no potential for a common
cause failure due to PD) (Both Units)
c.
Eliminating Station Blackout sequences where ELAP is successful but
Offsite power is not restored in 24/72 hours leading to core damage.
Case
Internal
Events
Fire
Other
External
Events
Total
Representative
Case U2
2.064E-6
3.96E-6
2.714E-7
6.295E-6
Representative
Case U1
6.704E-7
N/A
8.348E-8
7.539E-7
No FLEX U2
6.13E-6
3.96E-6
2.714E-7
1.03E-5
Nominal FLEX U2
3.73E-6
3.96E-6
2.714E-7
7.96E-6
N+1 FLEX U2
3.08E-6
3.96E-6
2.714E-7
7.31E-6
N+1 FLEX and
SAFER U2
2.83E-6
3.96E-6
2.714E-7
7.06E-6
Licensee Rep
Case U2
1.39E-6
3.96E-6
2.714E-7
5.62E-6
Licensee No
potential for
common cause
(CC) U2
1.04E-6
3.81E-6
2.714E-7
5.12E-6
Licensee
Truncation
1.39E-6
5.32E-6
2.714E-7
6.98E-6
Fail to Load run
U2
2.11E-6
3.96E-6
2.714E-7
6.34E-6
PD no Potential
2.40E-6
3.81E-6
2.714E-7
6.48E-6
for CC U2
Long Term offsite
power restoration
events removed
U2
1.25E-6
3.96E-6
2.714E-7
5.48E-6
PD no Potential
for CC U1
2.81E-7
N/A
8.348E-8
3.645E-7
Upper Bound U2
3.73E-6
5.32E-6
2.714E-7
9.32E-6
Lower Bound U2
1.04E-6
3.81E-6
2.714E-7
5.12E-6
Upper Bound U1
6.704E-7
N/A
8.348E-8
7.539E-7
Lower Bound U1
2.81E-7
N/A
8.348E-8
3.645E-7
Contributions from External Events:
Since change in core damage frequency (CDF) for internal events sequences was greater
than 1E-7 external events were required to be considered. The licensees draft fire PRA is
considered the best available information in this case. Table 7-1 summarizes the licensees
results and sensitivities. The SRA also considered Internal Flooding, Seismic and Tornado
High winds using the SPAR model. The delta CDF for internal flooding was negligible
because flooding sequences which affected the Emergency Switchgear room also failed the
2J EDG as a consequence of the flood so the 2J EDG FTS does not appear in the cutsets for
flooding as expected. Seismic and Tornado/High Winds were also minimal contributors.
Potential Risk Contribution from Large Early Release Frequency (LERF):
The SRA screened the finding for LERF in accordance IMC 0609 Appendix H. This would be
a Type A finding at power. Per Table 6.1 Phase 1 Screening-Type A Findings at Full Power
for a PWR with a Large Dry Sub atmospheric containment, SBO sequences screen out as
they are not a LERF contributor and are GREEN for LERF.
Qualitative Risk Considerations
The SPAR model Only models Unit 1; however, the offsite power distribution configurations
do differ between units. For Example, both the 2J and 1H emergency busses are fed from
transfer bus F and SUT C while the 1J emergency bus is exclusively fed the D transfer bus
and the A SUT. Additionally, a one-time configuration cross connecting the A and B SUT via
the 0L Bus (for the SBO EDG) was approved and implemented. Thus, it is reasonable the 2J
Bus could be fed via the 1H EDG thru the F Transfer Bus or via the A and/or B SUTs via the
0L and 0M SBO busses; however, there are no procedures directing this. Also, while
procedure would allow the SBO EDG to be aligned to a unit with one vital bus deenergized,
the operators would most likely re-align the SBO diesel to the other unit if both vital buses
were deenergized. (The SPAR logic does not consider this)