IR 05000254/2022001
| ML22130A771 | |
| Person / Time | |
|---|---|
| Site: | Quad Cities  |
| Issue date: | 05/11/2022 |
| From: | Reimer K NRC/RGN-III/DRP/B1 |
| To: | Rhoades D Constellation Energy Generation, Constellation Nuclear |
| References | |
| IR 2022001 | |
| Download: ML22130A771 (29) | |
Text
May 10, 2022
SUBJECT:
QUAD CITIES NUCLEAR POWER STATION - INTEGRATED INSPECTION REPORT 05000254/2022001 AND 05000265/2022001
Dear Mr. Rhoades:
On March 31, 2022, the U.S. Nuclear Regulatory Commission (NRC) completed an inspection at Quad Cities Nuclear Power Station. On April 19, 2022, the NRC inspectors discussed the results of this inspection with Mr. B. Wake, 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 III; the Director, Office of Enforcement; and the NRC Resident Inspector at Quad Cities Nuclear Power Station.
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 III; and the NRC Resident Inspector at Quad Cities Nuclear Power Station. This letter, its enclosure, and your response (if any) will be made available for public inspection and copying at http://www.nrc.gov/reading-rm/adams.html and at the NRC Public Document Room in accordance with Title 10 of the Code of Federal Regulations 2.390, Public Inspections, Exemptions, Requests for Withholding.
Sincerely, Kenneth R. Riemer, Chief Branch 1 Division of Reactor Projects
Docket Nos. 05000254 and 05000265 License Nos. DPR-29 and DPR-30
Enclosure:
As stated
Inspection Report
Docket Numbers:
05000254 and 05000265
License Numbers:
Report Numbers:
05000254/2022001 and 05000265/2022001
Enterprise Identifier: I-2022-001-0069
Licensee:
Constellation Nuclear
Facility:
Quad Cities Nuclear Power Station
Location:
Cordova, IL
Inspection Dates:
January 01, 2022 to March 31, 2022
Inspectors:
J. Bozga, Senior Reactor Inspector
Z. Coffman, Resident Inspector
R. Elliott, Resident Inspector
C. Hunt, Senior Resident Inspector
J. Neurauter, Senior Reactor Inspector
A. Nguyen, Senior Resident Inspector
Approved By:
Kenneth R. Riemer, Chief
Branch 1
Division of Reactor Projects
SUMMARY
The U.S. Nuclear Regulatory Commission (NRC) continued monitoring the licensees performance by conducting an integrated inspection at Quad Cities Nuclear Power Station, in accordance with the Reactor Oversight Process. The Reactor Oversight Process is the NRCs program for overseeing the safe operation of commercial nuclear power reactors. Refer to https://www.nrc.gov/reactors/operating/oversight.html for more information.
List of Findings and Violations
Failure to Perform an Adequate Maintenance Risk Assessment during Corrective Maintenance Activities Cornerstone Significance Cross-Cutting Aspect Report Section Mitigating Systems Green NCV 05000254,05000265/2022001-01 Open/Closed
[H.14] -
Conservative Bias 71111.13 Inspectors identified a finding of very low safety significance (Green) and associated non-cited violation of 10 CFR 50.65 (a)(4) for the licensee's failure to perform an adequate risk assessment prior to performing corrective maintenance activities on the Unit 1 HPCI gland seal exhaust (GSE) fan between December 1, 2021, and December 10, 2021. This resulted in the licensee not performing risk management actions as required per OP-AA-201-012-1001, Operations On-line Fire Risk Management.
Failure of High-Level Switch in HPCI Gland Seal Exhaust Condenser Cornerstone Significance Cross-Cutting Aspect Report Section Mitigating Systems Green FIN 05000254,05000265/2022001-03 Open/Closed
[H.14] -
Conservative Bias 71153 The inspectors identified a finding of very low safety significance (Green) for the licensee's failure to implement an effective maintenance strategy for the Unit 1 HPCI gland seal condenser high-level switch, 2-2341-8202, from February 7, 2012, to December 1, 2022. The failure to address a known aging-related degradation mechanism allowed the buildup of corrosion products in the switch float chamber and ultimately led to the switch failing during the quarterly surveillance testing of the HPCI system on December 1, 2021.
Additional Tracking Items
Type Issue Number Title Report Section Status URI 05000254/2019001-01 Insulation Not Removed Prior to General Visual Examination of Containment Surface Areas 71111.08G Discussed URI 05000254,05000265/2022001-02 Compliance With 10 CFR 50.55a and the Use of Alternate Operability Evaluations 71152S Open
LER 05000254/2022-001-00 LER 2022-001-00 for Quad Cities Nuclear Power Station, Unit 1 regarding "High Pressure Coolant Injection System Inoperable due to Gland Seal System Malfunction" 71153 Closed
PLANT STATUS
Unit 1
The unit began the inspection period at full-rated thermal power, where it remained for the entire inspection period, with the exception of short-term power reductions for control rod sequence exchanges, testing, and as requested by the transmission system operator.
Unit 2
The unit began the inspection period at full-rated thermal power. On January 28, 2022, the unit began its end-of-cycle coastdown period. The unit shut down on March 20, 2022, for refueling outage Q2R26 and remained in a shutdown condition through the end of the inspection period.
For all other periods, the unit was at full-rated thermal power with the exception of short-term power reductions for control rod sequence exchanges, testing, and as requested by the transmission system operator.
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, conducted routine reviews using IP 71152, Problem Identification and Resolution, observed risk-significant activities, and completed onsite portions of IPs. The inspectors reviewed selected procedures and records, observed activities, and interviewed personnel to assess licensee performance and compliance with Commission rules and regulations, license conditions, site procedures, and standards.
REACTOR SAFETY
71111.01 - Adverse Weather Protection
Seasonal Extreme Weather Sample (IP Section 03.01) (1 Sample)
- (1) The inspectors evaluated readiness for seasonal extreme weather conditions prior to the onset of seasonal cold temperatures for the following systems:
- station contaminated condensate storage tanks
- station blackout diesel generators
- Unit 1 and Unit 2, 125 Volt direct-current batteries
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)
'A' loop residual heat removal (RHR) on January 25, 2022
- (2) Unit 2 emergency diesel generator (EDG) during Unit 1 EDG cooling water pump maintenance on February 7, 2022
- (3) Unit 1 high pressure coolant injection (HPCI) during RHR work window on February 8, 2022
- (4) Unit 1 reactor core isolation cooling (RCIC) during Unit 1 HPCI motor-operated valve (MOV) work on February 28, 2022
- (5) Unit 2 shutdown cooling lineup on March 23, 2022
71111.05 - Fire Protection
Fire Area Walkdown and Inspection Sample (IP Section 03.01) (3 Samples)
The inspectors evaluated the implementation of the fire protection program by conducting a walkdown and performing a review to verify program compliance, equipment functionality, material condition, and operational readiness of the following fire areas:
- (1) Fire Zone 8.1; Unit 2 turbine building, clean and dirty oil room, elevation 595'-0" on January 26, 2022
- (2) Fire Zone 8.2.7.C, Unit 1/2 turbine building, elevation 611', adjustable speed drive oil coolers, on January 28, 2022 (3)hot work in the low-pressure heater bay during Q2R26 on March 29, 2022
71111.08G - Inservice Inspection Activities (BWR)
BWR Inservice Inspection Activities Sample - Nondestructive Examination and Welding
Activities (IP Section 03.01)
- (1) The inspectors verified that the reactor coolant system boundary, reactor vessel internals, risk-significant piping system boundaries, and containment boundary are appropriately monitored for degradation and that repairs and replacements were appropriately fabricated, examined and accepted by reviewing the following activities from March 21, 2022 to March 31, 2022:
03.01.a - Nondestructive Examination and Welding Activities.
1. Ultrasonic Testing (UT) of Core Spray Component ID 1402-5, Weld between
Elbow to Pipe
2. UT of Emergency Core Cooling (ECC) Component ID 1025-15, Weld between
Pipe to Pipe (2 Seam Welds)
3. UT of ECC Component ID 1025-44, Weld between Pipe to Pipe
(2 Seam Welds)
4. UT of ECC Component ID 1025-5, Weld between Pipe to Pipe
(2 Seam Welds)
5. UT of ECC Component ID 1025-9, Weld between Pipe to Pipe
(2 Seam Welds)
6. UT of Reactor Recirculation Component ID 02C-F7, Weld between Sweepolet
to Pipe (1 Seam Weld)
7. UT of Component ID VCS4-339, Reactor Pressure Vessel (RPV)
Vertical Weld
8. UT of Component ID RPV-CS-C4FLG, RPV Flange to Shell
Circumferential Weld
9. Visual examination (VT-3) of RR Component ID 0200-M-155 Variable Spring
Can Support 10. VT-3 of Reactor Water Cleanup Component ID 1202-M-106 Constant Spring Can Support 11. Magnetic Particle of Component ID RPV-SSLH, Weld between RPV Support Skirt to Lower Head 12. Liquid Penetrant (PT) of Component ID Control Rod Drive (CRD) Housing (Bottom) CRD Housings Flange to Pipe 13. PT of Component ID CRD Housing (Top) CRD Housings Pipe to Pipe 14. Pressure Boundary Welds Associated with Work Order 4830210, "Replace Piping Downstream of 2-1041-15A to Inlet of 2A RHRSW [residual heat removal service water] Room Cooler"
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 shutdown for refueling outage Q2R26 on March 20, 2022.
Licensed Operator Requalification Training/Examinations (IP Section 03.02) (1 Sample)
- (1) The inspectors observed and evaluated licensed operator requalification training in the simulator on February 3, 2022.
71111.12 - Maintenance Effectiveness
Maintenance Effectiveness (IP Section 03.01) (1 Sample)
The inspectors evaluated the effectiveness of maintenance to ensure the following structures, systems, and components (SSCs) remain capable of performing their intended function:
(1)primary containment system maintenance rule function PC0010-1 on February 14, 2022
71111.13 - Maintenance Risk Assessments and Emergent Work Control
Risk Assessment and Management Sample (IP Section 03.01) (8 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) Action Request (AR) 4465397, "NRC Question on U1 HPCI PRA Availability," on February 1, 2022 (2)emergent maintenance associated with the failure of the 1/2 emergency diesel generator cooling water pump to start on February 22, 2022
- (3) Unit 1 RCIC room cooler replacement on March 2, 2022 (4)shutdown safety plan review for Q2R26 on March 7, 2022
- (5) Unit 1 online work during Q2R26 outage on March 17, 2022
- (6) Unit 2 control room and multiple protected path walkdowns during Q2R26 on March 23, 2022
- (7) Unit 2 reactor vessel water inventory control during Q2R26 on March 24, 2022 (8)emergent repair work for current transformer failure on bus 23 during Q2R26 on March 28, 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 4468396, "1B RHR Room Cooler Low Flow," on February 4, 2022
- (2) AR 4467332, "VT-2 Identified Leak during U2 HPCI Run," on February 14, 2022
- (3) AR 4477311, "Low Readings on the 1-1001-65D LP [low pressure] Discharge Elbow,"
on February 14, 2022
- (4) AR 4479617, "1/2 EDG Cooling Water Pump Not Starting," on March 17, 2022
- (5) AR 4484760, "TS [Technical Specification] Surveillance Critical Date Missed," on March 18, 2022
71111.19 - Post-Maintenance Testing
Post-Maintenance Test Sample (IP Section 03.01) (1 Sample)
The inspectors evaluated the following post-maintenance testing activities to verify system operability and/or functionality:
(1)bus 23 'C' phase current transformer replacement and testing 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 Q2R26 refueling outage activities from March 20, 2022, to March 31, 2022.
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) (1 Sample)
- (1) QCOS 1400-17, "Unit 2 Division I Core Spray Logic Functional Test," on March 1, 2022
Inservice Testing (IP Section 03.01) (3 Samples)
- (1) QCOS 1300-05, "RCIC Pump Flow Rate Test," on January 5, 2022
- (2) QCOS 1400-07, "1B Core Spray Pump Comprehensive," on February 14, 2022
- (3) QCOS 1100-14, " Standby Liquid Control System Outage Surveillance," on March 30, 2022
Containment Isolation Valve Testing (IP Section 03.01) (1 Sample)
- (1) QCOS 0100-08, "RCIC Steam Supply Local Leak Rate Test MO 2-1301-16, MO 2-1301-17," on March 21, 2022
71114.06 - Drill Evaluation
Select Emergency Preparedness Drills and/or Training for Observation (IP Section 03.01) (1 Sample)
(1)emergency preparedness drill on February 8,
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)===
- (1) Unit 1 (January 1, 2021 through December 31, 2021)
- (2) Unit 2 (January 1, 2021 through December 31, 2021)
IE03: Unplanned Power Changes per 7000 Critical Hours Sample (IP Section 02.02) (2 Samples)
- (1) Unit 1 (January 1, 2021 through December 31, 2021)
- (2) Unit 2 (January 1, 2021 through December 31, 2021)
IE04: Unplanned Scrams with Complications (USwC) Sample (IP Section 02.03) (2 Samples)
- (1) Unit 1 (January 1, 2021 through December 31, 2021)
- (2) Unit 2 (January 1, 2021 through December 31, 2021)
===71152S - Semiannual Trend Problem Identification and Resolution
Semiannual Trend Review (Section 03.02)===
- (1) The inspectors reviewed a trend in the licensees use of the alternate evaluation method as described in OP-AA-108-115, Operability Determinations, for evaluating operability of safety-related components 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)
The inspectors evaluated the following licensee event reports (LERs):
- (1) LER 254/2022-001-00, "High Pressure Coolant Injection System Inoperable due to Gland Seal System Malfunction," (ADAMS Accession No. ML22026A288), on January 12,
INSPECTION RESULTS
URI (Discussed)
Insulation Not Removed Prior to General Visual Examination of Containment Surface Areas URI 05000254/2019001-01 71111.08G
Description:
The Quad Cities Nuclear Power Station (QCNPS), Units 1 and 2 - NRC Integrated Inspection Report 05000254/2019001; 05000265/2019001, dated May 6, 2019 (ADAMS Accession No.
ML19127A066), documents an unresolved item (URI) regarding the licensees general visual (GV) examination of surface areas covered by insulation. Specifically, on March 20, 2019, the inspector observed the licensees GV examination of Class MC surface areas of flued head components at piping penetrations X-007A, X-007B, X-007C, X-007D, X-008, X-009A, X 009B, X-010, and X-012. The inspector noted that the licensee had not removed thermal insulation covering these components, and the licensees examiners could only displace a relatively small portion of blanket-type insulation to visually examine the containment surface area under the insulation. For metallic-type insulation, the licensees examiners could not examine any portion of containment surface area covered by the insulation. The licensee documented these components as insulated in visual examination Nondestructive Examination (NDE) Report Q1R25-IWE-01, with no recordable/relevant indications identified for any of the 23 examination attributes listed in the NDE report.
On March 22, 2019, the licensee entered the concern into its corrective action program (CAP)as AR 4231978, NRC ISI Inspection - IWE Examination Accessibility Question. This report documented the licensee's position to follow American Society of Mechanical Engineers (ASME) Code Interpretation XI-1-13-25, Inquiry on IWE-2500 Related to Accessibility for Examination, issued on March 7, 2014, which stipulates:
- (1) It is not a requirement of IWE-I230 that containment surface covered by thermal insulation be considered accessible for general visual examination in accordance with Table IWE-2500-1, Examination Category E-A; and
- (2) It is a requirement of IWE-1230 that containment surface covered by thermal insulation be considered accessible for augmented examination in accordance with Table IWE-2500-1, Examination Category E-C, if these surfaces are subject to accelerated degradation or aging. In addition, the licensee cited paragraph IWE-1232(c) of Subsection IWE, to classify IWE Class MC surface areas covered by insulation as inaccessible: surface areas are considered inaccessible if visual access by line of sight from permanent vantage points is obstructed by permanent plant structures, equipment, or components, provided these surface areas do not require examination in accordance with the inspection plan or IWE-1240.
As documented in the above 2019 integrated inspection report, the licensee provided its position: Constellation procedures ER-AA-330-007 and ISI Program Plan, ER-QC-330-1001, adopt and implement the ASME provided definition of accessible and inaccessible as discussed under IWE-1231, IWE-1232, and Section XI Code Interpretation XI-1-13-25.
Industry practice for this area of inspection has been and continues to be to adopt the ASME-provided definition of accessible and inaccessible per the Section XI Code Interpretation XI-1-13-25. This Code Interpretation was utilized at QCNPS during Q1R25 IWE visual examinations. In addition, Assignment 02 of AR 4231978 directed action to fleet CISI Engineer to revise procedure ER-AA-330-007 to include Constellation position on Interpretation XI-1-13-25 and clarify definition of Accessible Areas.
At the end of the inspection, the inspector could not conclude that the licensee could classify IWE Class MC surface areas covered by existing but removable insulation as inaccessible when performing IWE-GV examinations. This issue was considered an URI pending further review, including consultation with Office of Nuclear Reactor Regulation (NRR) staff, to ascertain the acceptability of considering equipment inaccessible for IWE-GV examination of IWE Class MC surface areas if covered by existing but removable insulation (URI 05000254/2019001-01, "Insulation Not Removed Prior to General Visual Examination of Containment Surface Areas").
During this review, the inspector reviewed the licensees Inservice Inspection (ISI) Program Plan, 10 CFR Section 50.55a applicable ASME Codes and other requirements related to ISI of MC surface areas, the licensees license renewal application and associated NRC safety evaluation report with respect to ASME Subsection IWE provisions credited in the aging management program for IWE Class MC components, visual examination of flued head penetration bellows specified by Subsection IWE, and the licensees implementing procedures related to visual inspection of Class MC components. In addition, the inspector reviewed TS and the licensees Primary Containment Leakage Rate Testing Program, and related operating experience.
Currently, the inspector and licensee have differing conclusions regarding the requirement to remove thermal insulation prior to performing GV examinations in accordance with Table IWE-2500-1 Examination Category E-A.
The licensee utilized provisions of the 10 CFR 50.55a regulation, ASME Subsection IWE, and ASME Code Interpretation to conclude that removal of thermal insulation is not required prior to performing general visual examinations in accordance with Table IWE-2500-1, Examination Category E-A. With the insulation not removed, the licensee used the provisions of IWE-1232(c) to define surface areas specified in Table IWE-2500-1, Examination Category E-A, as inaccessible.
The inspector utilized different provisions of the 10 CFR 50.55a regulations, paragraphs 50.55a(g)(1) and 50.55a(g)(4), and ASME Subsection IWA, General Requirements, Subarticle IWA-1500, Accessibility, that are applicable to Subsection IWE, to conclude that removal of thermal insulation is required to provide examination access prior to performing general visual examinations in accordance with Table IWE-2500-1 Examination Category E-A. After the insulation is removed, then provisions of IWE-1232(c) can be used to define examination inaccessible surface areas.
The inspectors will continue to pursue applicability of various NRC processes and methods including, but not limited to, the Reactor Oversight Process (ROP), Technical Assistance Request (TAR) process (formally the Task Interface Agreement (TIA) process), and further consultation with NRR to resolve the differing interpretations of provisions of the ASME code and 50.55a regulations to obtain formal NRC position. URI 05000254/2019001-01 remains open, pending results of the applicable NRC process or method used to resolve the URI concern.
Failure to Perform an Adequate Maintenance Risk Assessment during Corrective Maintenance Activities Cornerstone Significance Cross-Cutting Aspect Report Section Mitigating Systems
Green NCV 05000254,05000265/2022001-01 Open/Closed
[H.14] -
Conservative Bias 71111.13 Inspectors identified a finding of very low safety significance (Green) and associated non-cited violation of 10 CFR 50.65 (a)(4) for the licensee's failure to perform an adequate risk assessment prior to performing corrective maintenance activities on the Unit 1 HPCI gland seal exhaust (GSE) fan between December 1, 2021, and December 10, 2021. This resulted in the licensee not performing risk management actions as required per OP-AA-201-012-1001, Operations On-line Fire Risk Management.
Description:
The HPCI GSE subsystem is a safety-related subsystem of the HPCI system. The gland seal condenser (GSC) receives gland steam leak-off from the turbine glands and the turbine stop valve stem, thus preventing contaminated steam release into the HPCI pump room. The GSE fan draws a vacuum in the condenser and discharges exhausted non-condensable to the reactor building ventilation system. Level switches on the GSC control its condensate pump, starting it at a high-level 2 inches below the inlet line, and stopping it at the low-level setpoint.
On December 1, 2021, during the quarterly surveillance test of the Unit 1 HPCI pump, high-level limit switch 2-2341-8202, associated with the HPCI GSC hotwell pump, failed. The failure of the high-level switch allowed water to rise to the level of the intake of the GSE fan and overload the motor. Subsequently, from December 1, 2021, to December 10, 2021, the GSE system remained out of service while the licensee performed corrective maintenance to repair the GSE fan and 250 Volt direct-current breaker.
Licensee calculation QDC-2300-M-0433, Quad Cities HPCI Room Thermal Analysis Loss of Gland Seal System, states that a failure of either the GSC pump, the GSE fan, or cooling water to the GSC, results in the failure of the GSE subsystem. The licensee probabilistic risk assessment (PRA) notebook, QC-PSA-005.06, Quad Cities Probabilistic Risk Assessment High Pressure Coolant Injection System (HPCI) Notebook, Revision 7, states that a failure of the GSE subsystem, as modeled in the sites PRA, results in the failure of the HPCI system to meet the success criteria for its credited PRA functions. Specifically, if the GSE subsystem is not available, steam that would otherwise be condensed in the GSC has the potential to enter the equipment space. This additional heat input is not accounted for in the current licensee calculations for environment qualification of the room. The HPCI room has a temperature sensor that is designed to trip the turbine at 155 degrees Fahrenheit. Therefore, the additional heat input from the failed GSE subsystem has the potential to cause an unwanted automatic trip of the HPCI turbine during an actual event.
Shortly after the equipment issue on December 1, 2021, the licensee declared the HPCI system operable and available despite the GSE fan being out of service. The inspectors questioned how the decision was made to determine that the HPCI system was available given the information documented in QDC-2300-M-0433 and QC-PSA-005.06. The licensee documented their response to inspectors' concerns in AR 4465397:
Engineering is reviewing the calculations and assumptions associated with this issue to determine if any other concerns exist. As of now, they have determined that the PRA analysis uses assumptions that are intended to be bounding, and as such are not appropriate for the specific configuration experienced by the site. A complete loss of gland seal system is assumed in the analysis vice a non-functional exhauster. Also, the calculation used to fail HPCI uses the high-temperature isolation setpoint as its failure criteria. The high-temperature isolation can be bypassed per QCOP 2300-14 and is allowed per our QGAs [emergency operating procedures]. The PRA acknowledges the ability of the operators to bypass the high-temperature isolation, but, again for conservatism, does not actually employ this action in the PRA model in response to actual room heat up.
Given the reduced steam flow into the area from the exhauster, versus the amount assumed in the calculations referenced in the PRA, the time to reach the isolation temperature will be extended from that used in the PRA. The ability of the operators to bypass a high-temperature isolation should it occur also extends the time during which HPCI is available. Given this information there is reasonable assurance that HPCI remains functional.
Regarding the information provided in AR 4465397, the inspectors noted the licensees statement that a complete loss of gland seal system is assumed in the analysis vice a non-functional exhauster directly contradicts the information made in both QDC-2300-M-0433 and QC-PSA-005.06. The licensee offered no technical basis for why the original calculations were conservative or how different, less conservative assumptions would affect overall HPCI system availability. The licensee also stated that the high-temperature isolation can be bypassed per QCOP 2300-14 and is allowed per the sites QGAs. Further, they stated that the PRA acknowledges the ability of the operators to bypass the high-temperature isolation, but again for conservatism, does not actually employ this action in the PRA model in response to actual room heat up. The licensee did not perform a technical evaluation to show why the PRA model was conservative or how the results of the PRA model would change if those conservatisms were removed. During subsequent discussions with the licensee PRA engineers, the licensee stated that operator action to bypass the HPCI room high-temperature trip is only included in the PRA for scenarios with a false high-temperature indication. If the gland seal system fails, which currently encompasses GSC leaks or GSE fan failures, the PRA model assumes that the isolation temperature will be exceeded for all mission times and HPCI will be unable to operate whether or not credit is taken for the bypass of the high-temperature trip.
Inspection Manual Chapter (IMC) 0308, Attachment 3, Appendix K, Technical Basis for Maintenance Risk Assessment and Risk Management Significant Determination Process, dated January 1, 2021, defines PRA function as:
PRA function refers to the ways in which the SSC can be used in a PRA to prevent an initiating event from resulting in core damage. An SSC may have more or different PRA functions than those functions for which it is credited in the design or licensing basis. For example, the design function of the core spray system may be limited to mitigation of large loss of coolant accidents (LOCAs). As such, the accident analysis may define a certain flowrate required to mitigate that accident. However, the core spray system can be credited in a PRA to provide coolant injection in any scenarios in which coolant injection is needed and pressure can be reduced such that the system can operate. Thus, the PRA function of the core spray system is not limited to the mitigation of large LOCAs and the system may be able to perform some of its other PRA functions without meeting its design flowrate.
The inspectors determined that, given the information available to the licensee at the time, the HPCI system was not able to fulfill all of its designated PRA functions and therefore, should have been declared unavailable between December 1, 2021, and December 10, 2021, while repairs were being made to the GSE fan.
The HPCI system is identified in the sites PRA model, PARAGON, as a fire risk-significant component. Licensee procedure OP-AA-201-012-1001, Operations On-line Fire Risk Management, Revision 4, defines an unavailable fire risk-significant component (UFRIC) as an unavailable mitigating system component identified in PARAGON with functions that are important to minimize core damage fire risk from fire initiators. Per direction in OP-AA-201-012-1001, if a UFRIC is scheduled for greater than 60 hours6.944444e-4 days <br />0.0167 hours <br />9.920635e-5 weeks <br />2.283e-5 months <br />, the licensee is to identify and apply risk management actions (RMA) to mitigate the fire risk or to maintain the function of other available fire risk important components when UFRIC components are unavailable. In this case, RMA checklists 1, 4, and 10 would have been directed to be performed once per shift during the window where repairs were being conducted on the GSE fan. Therefore, the inspectors determined that the licensee failed to perform an adequate risk assessment in accordance with 10 CFR 50.65 (a)(4) prior to the conduct of maintenance activities on the Unit 1 HPCI GSE fan, resulting in the failure to perform RMAs as required.
Corrective Actions: The licensee is reevaluating the current PRA model for refinements that will support the assumption that a failed GSE subsystem will not affect HPCI availability.
Corrective Action References: AR 4465397, "NRC Question on U1 HPCI PRA Availability"
Performance Assessment:
Performance Deficiency: Failure to perform an adequate risk assessment in accordance with 10 CFR 50.65 (a)(4) prior to the conduct of maintenance activities.
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 GSE fan, and by extension the GSE subsystem, is required for the HPCI system to perform all of its designated PRA functions. Therefore, the Unit 1 HPCI system was unavailable from December 1, 2021, to December 10, 2021, while the GSE fan was out of service for repairs.
Inspectors reviewed the examples provided in IMC 0612, Appendix E, "Examples of Minor Issues," and determined that the more than minor discussion under example 8.d was appropriate because the inadequate risk assessment resulted in missed risk management actions that would have otherwise been assigned per plant procedures. Additionally, the more than minor discussion under several sub examples listed in example 3 also applies.
Specifically, the licensee is reevaluating the temperature assumptions for the HPCI room during a GSE subsystem failure solely to obtain favorable results.
Significance: The inspectors assessed the significance of the finding using Appendix K, Maintenance Risk Assessment and Risk Management SDP. The inspectors calculated the incremental core damage probability deficit (ICDPD) and incremental large early release probability deficit (ILERPD) in accordance with IMC 0612, Appendix K, Steps 04.01 and 04.02, and determined that both were less than 1E-6 and 1E-7, respectively. Per Flowchart 1, the issue screens to very low safety significance (Green).
Cross-Cutting Aspect: H.14 - Conservative Bias: Individuals use decision making practices that emphasize prudent choices over those that are simply allowable. A proposed action is determined to be safe in order to proceed, rather than unsafe in order to stop. Specifically, the licensee had information documenting that the HPCI system cannot fulfill all of its designated PRA functions without a functional GSE subsystem. When inspectors questioned the availability of HPCI during corrective repairs to the GSE fan, the licensee maintained that the HPCI system was available, without technical justification or rigor, contrary to the information the licensee already had documented in the PRA model.
Enforcement:
Violation: Title 10 CFR 50.65(a)(4) states that before performing maintenance activities (including but not limited to surveillance, post-maintenance testing, and corrective and preventive maintenance), the licensee shall assess and manage the increase in risk that may result from the proposed maintenance activities. The scope of the assessment may be limited to SSCs that a risk-informed evaluation process has shown to be significant to public health and safety.
Contrary to the above, from December 1, 2021, to December 10, 2021, the licensee failed to perform an adequate risk assessment in accordance with 10 CFR 50.65 (a)(4) prior to the conduct of maintenance activities. Specifically, the licensee failed to adequately assess the availability of the Unit 1 HPCI system during corrective maintenance on the GSE fan, resulting in the failure to perform RMAs as required by site procedures.
Enforcement Action: This violation is being treated as a non-cited violation, consistent with Section 2.3.2 of the Enforcement Policy.
Unresolved Item (Open)
Compliance With 10 CFR 50.55a and the Use of Alternate Operability Evaluations URI 05000254,05000265/2022001-02 71152S
Description:
The inspectors performed a review of the licensees use of the alternate evaluation method for determining operability of an ASME Code Class 2 or 3 component with operational leakage in accordance with licensee procedure OP-AA-108-115, Operability Determinations, Revision 24. The inspectors identified three instances where the licensee applied the alternate evaluation method provision of OP-AA-108-115 to address operational leakage:
- AR 4386700, "Pin-hole Leaks Found at Weld for 0-5799-381 B HVAC Train," dated November 27, 2020
- AR 4466003, "Pin-hole Leaks Found at Weld for 0-5799-381 B HVAC Train," dated December 11, 2021
- AR 4467332, "VT-2 Identified Leak During U2 HPCI Run," dated December 17, 2021
For Code Class 2 or 3 components, the licensees Technical Requirements Manual, 3.4.a, Structural Integrity, states that if structural integrity of one or more ASME components are not in conformance, the required action is to immediately restore the structural integrity of the affected component to within its limits or isolate the affected component.
OP-AA-108-115, Section 4.5.9, Flaw Evaluation, step 3, states, in part:
When a flaw is identified in ASME Class 2 or Class 3 components, then determination of whether the deficient condition results in a TS required SSC or a TS required support SSC being inoperable shall be made. The evaluation methodologies used must meet ASME Code, construction code acceptance standards, an NRC-accepted ASME Code Case as listed in Regulatory Guide 1.147, or an NRC approved alternative. If NRC approved code cases or other NRC approved alternate methods are not available to be used, station technical resources should use other alternative evaluation methods as outlined in Appendix A.2 of NEI 18-03.
In each instance identified, the licensee documented a through-wall leak in either a Code Class 2 or 3 component. The licensee determined that there was no applicable NRC approved Code Case to evaluate the through-wall condition, applied the alternate evaluation methodology to evaluate the structural integrity of the affected component, determined the affected component and corresponding safety-related systems were operable with through-wall leakage present, and continued to operate the system until repairs were made.
In each instance the licensee conducted repairs within the TS-allowed outage time.
Title 10 CFR 50.55a(g), requires the use of Section XI, Rules for Inservice Inspection of Nuclear Power Plant Components, of the ASME boiler pressure vessel (BPV) Code which provides methods to ensure the structural integrity of Code Class 1, 2, or 3 components that are required to be operable according to the licensees TS. These methods include a series of ASME BPV Code Cases (e.g., N-513, N-705) and Nonmandatory Appendix U, Evaluation Criteria for Temporary Acceptance of Flaws in Moderate Energy Piping and Class 2 or 3 Vessels and Tanks, to ASME BPV Code,Section XI.
Alternatively, if the licensee is unable to use one of the ASME BPV methodologies to evaluate structural integrity, ASME Code Section XI, Article IWA-4421, General Requirements, requires the defect in the Code component to be removed. Specifically, Article IWA-4422.1, Defect Evaluation, states, in part, that a defect is considered removed when it has been reduced to acceptable size. If the resulting section thickness is less than the minimum required thickness, the component shall be corrected by repair/replacement activities. By its nature, a through-wall defect does not meet the minimum required thickness of the affected component.
The repairs required by the ASME Code restore the component to a condition which ensures adequate design margins to preclude in-service failures. As an alternative to the ASME Code Section XI required repair, the NRC has approved several ASME Code Cases documenting methods for temporary acceptance of a defect until repairs can be affected. These Code Cases ensure that adequate structural integrity exists during that temporary period.
Normally, if an NRC Code Case is not applicable, then the licensee must conform with the provisions of ASME Section XI, the construction code of record, or seek NRC approval for an alternative method.
Industry guidance document Nuclear Energy Institute (NEI) 18-03, Operability Determination, Appendix A.2, allows the use of an alternative evaluation method if an NRC approved Code Case or other NRC approved method is not available. This guidance was incorporated in licensee procedure OP-AA-108-115, Operability Determinations, Revision 24, Attachment 3, which was used to disposition the three instances of through-wall leakage described above. NEI 18-03 is not approved by the NRC and therefore the use of an alternative method in lieu of an approved ASME or NRC methodology to disposition the through-wall leakage may constitute a violation of NRC regulation 10 CFR 50.55(a)(g)(4)which requires compliance with the ASME Section XI Code.
For the instances described above, the inspectors concluded that since the licensee completed Code repairs to the affected components within the allowed TS LCO time, there are no current safety concerns. However, the licensees inclusion of the NEI 18-03 guidance in licensee procedure OP-AA-108-115, allowing alternate disposition of through-wall leaks in Code Class 2 or 3 piping contrary to ASME Section XI requirements, may constitute a performance deficiency. This performance deficiency would be more than minor because, if left incorrected, it could result in subsequent licensee decisions to operate future degraded ASME Code Class 2 and 3 components without adequate demonstration of structural integrity, potentially increasing the probability of an in-service failure of such components.
Planned Closure Actions: The licensee and industry believe that the use of an alternative evaluation per NEI 18-03 is an acceptable method to disposition defects in ASME Code Class 2 and 3 components. The NRC is evaluating the use of the NEI 18-03 guidance and is developing a Regulatory Information Summary (RIS) to disposition this issue. Until this RIS is issued, it is unclear if the use of this guidance constitutes a violation of 10 CFR 50.55(a)(g)(4)and whether its inclusion in licensee procedure OP-AA-108-115 is a performance deficiency.
Therefore, this issue is considered an unresolved item pending the NRC issuance of the RIS.
(URI 05000254,05000265/2022001-02)
Licensee Actions: The licensee has documented the inspectors concerns in the CAP under AR 4391077.
Corrective Action References: AR 4391077, "Use of OP-AA-108-115 for Alternate Methods" Failure of High-Level Switch in HPCI Gland Seal Exhaust Condenser Cornerstone Significance Cross-Cutting Aspect Report Section Mitigating Systems
Green FIN 05000254,05000265/2022001-03 Open/Closed
[H.14] -
Conservative Bias 71153 The inspectors identified a finding of very low safety significance (Green) for the licensee's failure to implement an effective maintenance strategy for the Unit 1 HPCI gland seal condenser high-level switch, 2-2341-8202, from February 7, 2012, to December 1, 2022. The failure to address a known aging-related degradation mechanism allowed the buildup of corrosion products in the switch float chamber and ultimately led to the switch failing during the quarterly surveillance testing of the HPCI system on December 1, 2021.
Description:
On December 1, 2021, during the quarterly surveillance test of the Unit 1 HPCI pump, high-level limit switch 2-2341-8202, associated with the HPCI GSC hotwell pump, failed. The failure of the high-level switch allowed water to rise to the level of the GSE fan and overload the motor. This resulted in an alarm in the main control room and large amounts of smoke from the associated motor control center and locally in the HPCI room. Control room operators manually tripped/latched the HPCI turbine and aborted the surveillance. HPCI was declared inoperable and unavailable following these actions as it could not automatically initiate in the trip/latched condition to perform its safety-related function. The control room declared HPCI Operable and Available approximately 1.5 hours5.787037e-5 days <br />0.00139 hours <br />8.267196e-6 weeks <br />1.9025e-6 months <br /> later, after performing subsequent troubleshooting and evaluation. On December 2, 2021, the high-level float limit failed again during corrective maintenance, prompting control room operators to manually start the GSC condenser pump to prevent the condenser from over filling. On December 3, 2021, the licensee removed the HPCI GSE subsystem from service to replace both the failed high-level limit switch and the GSE fan.
The licensee entered the issue into the CAP and performed a corrective action program evaluation (CAPE) under AR 4464815. The cause of the high-level switch failure was determined to be aging-related degradation where corrosion products in the switch float chamber impeded switch operation.
The HPCI GSE subsystem is a safety-related subsystem of the HPCI system. The GSC receives gland leak-off from the turbine glands and the turbine stop valve stem, thus preventing contaminated steam release into the HPCI pump room. The GSE fan draws a vacuum in the condenser and discharges exhausted non-condensable to the reactor building ventilation system. Level switches on the GSC control its condensate pump, starting it at a high-level 2 inches below the inlet line and stopping it at the low-level setpoint.
The GSE subsystem supports risk significant HPCI system functions beyond the design basis mission time in the Updated Final Safety Analysis Report (UFSAR) and both the gland seal condensate pump and the gland seal exhaust fan are modeled in the sites PRA. The loss of either the exhaust fan or the condensate pump results in the failure of the GSE subsystem per calculation QDC-2300-M-0433. Site operating experience shows that, absent operator actions, a failure of either the high-level switch or the low-level switch results in the failure of the GSE subsystem because either the exhaust fan becomes overloaded as it attempts to pump water, or the condensate pump becomes overloaded due to continuously cycling. Per QC-PSA-005.06, Quad Cities Probabilistic Risk Assessment High Pressure Coolant Injection System (HPCI) Notebook, Revision 7, a failure of the GSE subsystem, as modeled in the sites PRA, results in the failure of HPCI to meet the success criteria for its credited PRA functions. In addition, a failure of HPCI adversely affects the sites fire risk.
Licensee procedure ER-AA-200, Preventive Maintenance Program, governs the performance of preventive maintenance at the site. ER-AA-200 states that the purpose of the program, using Performance Centered Maintenance (PCM), Maintenance Strategy Tools and other processes, is to maintain plant SSCs at an appropriate state of reliability based on relative importance of the SSCs to safety, production, and cost.
Procedure ER-AA-200, Step 4.3.8, states:
Failure modes and degradation mechanisms should be understood when determining the maintenance task and the preventive maintenance should be designed to address the failure modes and degradation mechanisms.
Both the high-level switch, 2-2341-8202, and the low-level switch, 2-2431-8203, are float style level switches. These switches actuate when water entering the switchs float chamber eventually fills the chamber to the point where the buoyant force of a float attached to the lever arm of the switch causes the switch to change state as the float rises and falls with the water level in the chamber. Both switches are considered safety-related and, other than the level at which each switch taps off the GSC, the switches are identical.
Between 2004 and 2021, the licensee has experience multiple failures of either the high-level switch or the low-level switch in the GSC on both Unit 1 and Unit 2. Those events were captured in the CAP as follows:
AR 265149265149 "Unit One HPCI Signal Converter Trouble," October 19, 2004 AR 326155326155 "U-1 HPCI Condensate Pump Level Switch Sticking," April 18, 2005 AR 325664325664 "Unit 1 HPCI GSC Hotwell Pump Failed to Automatically Start," April 18, 2005 AR 387540387540 "Unit 1 HPCI GSC Howell Pump Failed to Automatically Start," October 18, 2005 AR 495818495818 "HPCI Low Level Switch Not Functioning," June 1, 2006 AR 524997524997 "HPCI Gland Seal HW Pump Cycled Repeatedly," August 29, 2006 AR 456103456103 "PSU Q2R19 Troubleshoot LS 2-2341-8202," March 28, 2008 AR 1325643, "U2 HPCI Gland Seal Hotwell Low Level Switch Sticks," February 11, 2012 AR 1326791, "U1 HPCI GSC Pump Failed to Trip on Low Level," February 14, 2012 AR 4464185, "U1 HPCI Gland Exhauster Tripped," December 1, 2021
The licensees preventive maintenance program PCM template provides two recommended preventive maintenance activities for these types of float switches: a calibration of the switch on a predetermined interval, or a replacement/refurbishment of the switch on an interval determined by the component's classification. In addition to the recommendations from the PCM template, the vendor manual states that upon final installation, no routine maintenance is required for the switch. This model of switch is not serviceable or repairable. The vendor manual does not specify an expected service life of the limit switch.
Upon review of the licensees maintenance program, the inspectors identified that, although a calibration is listed in the PCM template, the licensee is not performing a calibration on the high-level or the low-level switches. The licensee documented in 2005, following a failure of the high-level switch on Unit 1, that calibrations were not possible given the way the switches are sent to the site from the manufacturer. Additionally, the licensee classifies the high-level limit switch as non-critical"; therefore, the switch is allowed to be replaced as required with no predetermined frequency in accordance with program guidance. Contrary to the high-level limit switch, the low-level limit switch, which is also classified as non-critical, has a 4-year replacement activity scheduled stemming from a corrective action from a failure documented in Equipment Apparent Cause Evaluation (EACE) 1324066 from 2012. During discussions with the licensee, the licensee stated that a visual inspection of the switch on a 4-year interval, in conjunction with testing the functionality of the switch during the HPCI quarterly surveillance as discussed below, is the current preventive maintenance strategy to ensure that the switch is functioning correctly.
In regard to the preventive maintenance activities being performed, the inspectors noted that the visual inspection by the site is not an intrusive inspection. It does not inspect the level switch float chamber or the connective piping. It does not include an inspection of the linkages between the switch and the float. It does not actuate the level switch from the float to determine if there are any impediments to switch actuation.
In regard to functional testing, in 2006 the licensee revised QCOS 2300-15, HPCI Drain Pot/Steam Line Drain Level Switch, Valve, and Alarm Functional Verification, to have technicians actuate the high and low-level switches in the GSC manually by hand to verify functionality. This surveillance was performed quarterly. In 2007, those preventive maintenance activities were removed from the surveillance. During discussions with the inspectors the licensee indicated that those activities were removed because manually actuating the switch by hand was causing issues with the switches hanging up or sticking in the open or closed position post maintenance. As a replacement to manual actuation, the licensee stated that they credit functional testing of the high and low-level switches through the HPCI quarterly surveillance test QCOS 2300-05, HPCI Pump Operability Test."
However, in reference to a failure of the low-level switch in 2012 on Unit 2, inspectors noted that EACE 1324066 states, in part:
The HPCI system is run quarterly in order to satisfy IST requirements and to observe system performance. Such testing can be used to trend certain parameters (flow, pressure, vibration, temperature) in order to predict a problem, and specify corrective actions before a failure.
However, such functional testing cannot directly measure or observe gradual degradation mechanisms caused by buildup inside individual components. Such degradation mechanisms can result in a self-revealing failure for a standby system that is discovered during its next periodic test run.
This was coded a repeat failure because weve had this same event happen approximately six years ago. However, based on the inability to directly measure or observe internal degradation, periodic functional testing continues to be the best practice to identify minor equipment problems before they become a safety-significant issue.
Based on the licensees evaluation, the inspectors determined that since 2012, the licensee was aware that the preventive maintenance activities being performed, a visual inspection on a 4 year frequency and functional testing of the GSC level switches during the quarterly HPCI operability test, failed to address a known aging-related degradation mechanism that operating experience has shown to occur in both the high-level and low-level switch float chambers. Therefore, under the current maintenance strategy, the HPCI system is vulnerable to a failure of the high-level switch occurring between quarterly surveillance tests that could result in an actual in-service failure of the GSE subsystem if HPCI is called upon to respond to an event.
Corrective Actions: The licensee performed a CAPE under AR 4464815. Actions generated from the evaluation include creating a new preventive maintenance activity to replace the high-level switches in the Units 1 and 2 HPCI GSC every 8 years.
Corrective Action References: AR 4464185, "U1 HPCI Gland Exhauster Tripped,"
AR 4464484, "HPCI Condensate Pump 1-2304 Failed to Start"
Performance Assessment:
Performance Deficiency: The inspectors determined that the failure to establish an effective maintenance strategy for the Unit 1 high-level switch, 2-2341-8202, was a performance deficiency. Specifically, from February 7, 2012, to December 1, 2021, none of the preventive maintenance activities being performed on the high-level switch addressed aging-related degradation of the float switch, a known degradation mechanism. As such, the buildup of corrosion products was allowed to proceed unmitigated in the high-level switch float chamber until the switch was no longer able to operate as designed.
Screening: The inspectors determined the performance deficiency was more than minor because if left uncorrected, it would have the potential to lead to a more significant safety concern. Specifically, under the current maintenance strategy, the HPCI system is vulnerable to a failure of the high-level switch occurring between quarterly surveillance tests. Should the high-level switch fail prior to a valid HPCI system actuation, the GSE subsystem would fail and result the failure of the HPCI system to meet all of its designated PRA functions.
Significance: The inspectors assessed the significance of the finding using Appendix A, The Significance Determination Process (SDP) for Findings At-Power. The inspectors screened the finding against the Mitigating Systems screening questions in Exhibit 2 and answered "No" to all six screening questions. Therefore, the finding screened to very low safety significance (Green).
Cross-Cutting Aspect: H.14 - Conservative Bias: Individuals use decision making practices that emphasize prudent choices over those that are simply allowable. A proposed action is determined to be safe in order to proceed, rather than unsafe in order to stop. Specifically, the licensee had indication in 2012 that the maintenance strategy was not effective in addressing a known degradation mechanism in the high-level float switch but failed to take proactive action to correct the deficiency because the degraded condition in 2012 didn't specifically affect the high-level switch.
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 19, 2022, the inspectors presented the integrated inspection results to Mr. B. Wake, Site Vice President, and other members of the licensee staff.
- On March 31, 2022, the inspectors presented the Unit 2 inservice inspection results to Ms. D. Fuson, Director of Operational Effectiveness and Regulatory, and other members of the licensee staff.
DOCUMENTS REVIEWED
Inspection
Procedure
Type
Designation
Description or Title
Revision or
Date
Miscellaneous
SVP-21-062
Site Certification of Winter Readiness
11/03/2021
Procedures
QCOP 0010-01
Winterizing Checklist
QCOP 0010-02
Required Cold Weather Routines
Drawings
Drawing M-37
Diagram of RHR Service Water Piping
BL
Drawing M-81,
Sheet 3
Diagram of Residual Heat Removal RHR Piping
F
Procedures
QCOP 1000-05
Shutdown Cooling Operation
QCOS 1000-26
RHR Valve Position Verification
Corrective Action
Documents
Resulting from
Inspection
NRC ID: Extinguishers in Field do not Match Pre-Fire Plan
2/01/2022
Drawings
Drawing 4E-2200
Station Emergency Lighting Battery Operated Light Units
S
Drawing F-14-1
Detection and Suppression Turbine Building Mezzanine
Floor
M
Drawing M-393
Turbine Building Ventilation Plan - Ground Floor
U
Fire Plans
NRC ID: Hose Station 1-2-52-F2 and Extinguisher Impeded
2/01/2022
FZ 8.1
Unit 1/2 TB 595'-0" Elev. Clean and Dirty Oil Room
July 2009
FZ 8.2.6.D
Unit 2 TB 595' Elevation, Low Pressure Heater Bay
March 2018
FZ 8.2.6.E
Unit 2 TB 595' Elevation, 'D' Heater Bay
October
2013
FZ 8.2.7.C
Unit 1/2 TB 611'-6" Elev. ASD Oil Coolers
March 2018
Procedures
Fire Prevention for Hot Work
71111.08G Corrective Action
Documents
Clarify CISI Drawings for Visual Examination Accessibility
07/22/2020
U2 RHRSW LP Pump Suction Piping UT Results
09/10/2021
Corrective Action
Documents
Resulting from
Inspection
NRC ISI Inspection - IWE Examination Accessibility
Question
03/20/2019
Miscellaneous
License Renewal Application, Dresden Nuclear Power
Station, Units 2 and 3 and Quad Cities Nuclear Power
Station Units 1 and 2
January
2003
Inspection
Procedure
Type
Designation
Description or Title
Revision or
Date
ER-QC-330-1001
Quad Cities Generating Station, Units 1 & 2: Inservice
Inspection (ISI) Plan
ER-QC-330-1003
Quad Cities Generating Station, Units 1 & 2: Inservice
Inspection (IS) Classification Basis Document
ER-QC-330-1003
Quad Cities Generating Station, Units 1 & 2: Inservice
Inspection (ISI) Classification Basis Document
ER-QC-330-1005
Quad Cities Generating Station, Units 1 & 2: Inservice
Inspection (ISI) Selection Document
Safety Evaluation Report Related to the License Renewal of
the Dresden Nuclear Power Station, Units 2 and 3 and Quad
Cities Nuclear Power Station, Units 1 and 2
July 2004
Licensee Letter to NRC, Subject: Additional Information for
the Review of the License Renewal Applications for Quad
Cities Nuclear Power Station, Units 1 and 2 and Dresden
Nuclear Power Station, Units 2 and 3
10/03/2003
Licensee Letter to NRC, Subject: Additional Information for
the review of the License Renewal Application for Dresden
Nuclear Power Station, Units 2 and 3 and Quad Cities
Nuclear Power Station, Units 1 and 2
2/05/2003
XI-1-13-25
ASME Section XI Code Interpretation: Inquiry on IWE-2500
Related to Accessibility for Examination
03/07/2014
NDE Reports
EE2-22-331685-
RPVID
Weld No. RPV-CW-C4FLG
04/05/2022
EE2-22-331685-
RPVID
Automated lnvessel RPV Calibrations
04/02/2022
EE2-22-331685-
RPVID
Weld No. RPV-VSC4-339
04/03/2022
Procedures
Visual Examination of Section XI Class MC and Metallic
Liners of Class CC Components
Liquid Penetrant (PT) Examination
Visual Examination of ASME IWE Class MC and Metallic
Liners of IWL Class CC Components
GEH-PDI-UT-1
PDI Generic Procedure for the Ultrasonic Examination of
Ferritic Welds
Inspection
Procedure
Type
Designation
Description or Title
Revision or
Date
GEH-UT-737
Procedure for the Examination of Reactor Pressure Vessel
Welds from the Inside Surface with the Z-Scan UT
System in Accordance with Appendix VIII
Work Orders
Replace Piping Downstream of 2-1041-15A to Inlet of
2A RHRSW Room Cooler
03/29/2021
Corrective Action
Documents
EO ID - U1 Electrical Penetration 104F Doesn't Hold
Pressure
08/30/2019
EO ID - U1 Electrical Penetration 105B Doesn't Hold
Pressure
08/30/2019
Penetration 105A Won't Hold Pressure
11/26/2019
IEMA ID: Reference for QCOS 1600-16
2/03/2022
Miscellaneous
SESR 4-1871
Site Engineering Service Request - Primary Containment
Electrical Penetrations
Procedures
Primary Containment Leak Rate Testing Program
QCOS 1600-16
Primary Containment Electrical Penetration Pressures
Corrective Action
Documents
NRC Question on U1 HPCI PRA Availability
2/08/2021
EO ID: 1/2 EDG Cooling Water Pump Not Starting
2/21/2022
Miscellaneous
QC-PSA-005.06
Quad Cities Probabilistic Risk Assessment High Pressure
Coolant Injection (HPCI) Notebook
Procedures
AC Sources-
Operating 3.8.1
3.8 Electrical Power Systems
OP-QC-107-1001
Quad Cities Risk Management Guidelines
Shutdown Safety Management Program
OU-QC-104
Shutdown Safety Management Quad Cities Annex
QCAP 0260-03
Screening for Reactor Pressure Vessel Water Inventory
Control
QCOA 6600-14
Loss of a Diesel Generator Cooling Water Pump
QCOP 6500-08
4kV Bus Cross-Tie Operation
QCOP 6500-08
4kV Bus Cross-Tie Operation
QCOP 6500-09
Energize 4kV Switchgear and Transfer Auxiliary Power
QCOP 6500-23
De-energize 4kV Bus 23 for Maintenance and Re-energize
QCOP 6600-14
Emergency Diesel Generator Cooling Water Pump Manual
Operation
Inspection
Procedure
Type
Designation
Description or Title
Revision or
Date
QCOS 6600-43
Unit 1/2 Emergency Diesel Generator Load Test
QOP 6700-02
480 Volt Bus Tie Circuit Breakers
Work Orders
Replace 1A Core Spray Room Cooler 1-5748-A
03/08/2022
Corrective Action
Documents
EO ID: 1B RHR Room Cooler Flow
2/03/2021
VT-2 Identified Leak During U2 HPCI Run
2/17/2021
EO ID: 1B RHR Room Cooler Low Flow
2/27/2021
Low Readings on the 1-1001-65D LP Discharge Elbow
2/10/2022
EO ID-1-2 EDG Cooling Water Pump Not Starting
2/21/2022
Follow Up to IR 4479617 for the 1/2 EDGCWP
Troubleshooting
2/24/2022
TS Surveillance Critical Date Missed
03/14/2022
Corrective Action
Documents
Resulting from
Inspection
NRC ID U2 HPCI Op Eval EOC WO Not Coded Correctly
03/03/2022
NRC Identified: Discrepancy Within Op Eval EC 635854
03/04/2022
Engineering
Changes
Emergency Core Cooling System (ECCS) Room Cooler
Performance Calculation Under Design Basis and Degraded
Conditions
Emergency Core Cooling System (ECCS) Room Cooler
Performance Calculation Under Design Basis and Degraded
Conditions
HPCI Booster Pump Recirc Line 2-23108B-1/2 Through
Wall Leak
Low Thickness Readings on the RHRSW 1-1001-65D LP
Discharge Elbow Operability Evaluation
Miscellaneous
Design Analysis
No.: QDC-5700-
M-0806
Emergency Core Cooling System (ECCS) Room Cooler
Performance Calculation Under Design Basis and Degraded
Conditions
001
QDC-57352
Failure Analysis and Flaw Characterization of 1/2 Carbon
Steel Tubing
01/12/2022
NDE Reports
22-UT-012
1-1001-65D LP & HP Discharge Elbows
2/10/2022
Procedures
QCIS 0200-11
Reactor Low Pressure (RHR-LPCI) Calibration and
Functional Test
QCIS 0200-12
Reactor Low Pressure (RHR-LPCI) Functional Test
Inspection
Procedure
Type
Designation
Description or Title
Revision or
Date
QCOS 5750-09
ECCS Room and DGCWP Cubicle Cooler Monthly
Surveillance
QCOS 5750-09
ECCS Room and DGCWP Cubicle Cooler Monthly
Surveillance
Corrective Action
Documents
PSU Concern Regarding Current Transformer Test Results
03/27/2022
Work Orders
Bus 23, Cubicle 4 Current Transformer Replacement
03/31/2022
Corrective Action
Documents
Q2R26 LLRT on 2-1301-17 Exceeded Admin Alarm Limit
03/21/2022
Procedures
QCOS 0100-08
RCIC Steam Supply Local Leak Rate Test MO 1(2)-1301-16,
MO 1(2)-1301-17
QCOS 1100-14
Standby Liquid Control System Outage Surveillance
QCOS 1300-05
RCIC Pump Operability Test
QCOS 1400-17
Unit 2 Division I Core Spray Logic Functional Test
71152S
Corrective Action
Documents
Pin-Hole Leaks Found at Weld for 0-5799-381 'B' HVAC
Train
11/27/2020
Pin-Hole Leaks Found at Weld for 0-5799-381 'B' HVAC
Train
2/11/2021
VT-2 Identified Leak During U2 HPCI Run
2/17/2021
Engineering
Changes
CR HVAC B Train Pining Line 0-57479-2 1/2" Through Wall
Leak
CR HVAC Train Piping Line 0-57479-2.5" Leak at
1/2-5799-381
Corrective Action
Documents
U2 HPCI Gland Seal Hotwell Pump Overload During QCOS
2300-05
2/07/2012
AR 326155326155U-1 HPCI Condensate Pump Level Switch Sticking
04/19/2005
AR 387540387540Unit 1 HPCI GSC Hotwell Pump Failed to Automatically Start 10/18/2005
U1 HPCI Gland Exhauster Tripped
2/01/2021
Procedures
Preventive Maintenance Program
QCOS 2300-05
HPCI Pump Operability Test
88