IR 05000259/2023090
| ML23048A062 | |
| Person / Time | |
|---|---|
| Site: | Browns Ferry  |
| Issue date: | 03/02/2023 |
| From: | Ladonna Suggs Division Reactor Projects II |
| To: | Jim Barstow Tennessee Valley Authority |
| References | |
| EA-22-122 IR 2023090 | |
| Download: ML23048A062 (15) | |
Text
SUBJECT:
BROWNS FERRY NUCLEAR PLANT - NRC INSPECTION REPORT 05000259/2023090 AND 05000260/2023090 AND PRELIMINARY WHITE FINDING AND APPARENT VIOLATION
Dear Jim Barstow:
The enclosed report documents a finding with an associated apparent violation that the U.S.
Nuclear Regulatory Commission (NRC) has preliminarily determined to be White with low-to-moderate safety significance. This involved an NRC-identified apparent violation of Title 10 of the Code of Federal Regulations (10 CFR) Part 50, Appendix B, Criterion XVI, associated with the licensee's failure to identify and correct a condition adverse to quality associated with the electric governor remote (EG-R) and remote servo subcomponents. This resulted in the inoperability of the Browns Ferry Unit 1 high pressure coolant injection (HPCI) system on July 12, 2022. We assessed the significance of the finding using the significance determination process (SDP) and best available information. We are considering escalated enforcement for the apparent violation consistent with our Enforcement Policy, which can be found at http://www.nrc.gov/about-nrc/regulatory/enforcement/enforce-pol.html. Because we have not made a final determination, no notice of violation is being issued at this time. Please be aware that further NRC review may prompt us to modify the number and characterization of the apparent violation.
The NRCs significance determination process is designed to encourage an open dialogue between your staff and the NRC; however, neither the dialogue nor the written information you provide should affect the timeliness of our final determination.
Before we make a final decision on this matter, we are providing you with an opportunity to (1) attend a Regulatory Conference where you can present to the NRC your perspective on the facts and assumptions the NRC used to arrive at the finding and assess its significance, or (2) submit your position on the finding to the NRC in writing. If you request a Regulatory Conference, it should be held within 40 days of the receipt of this letter, and we encourage you to submit supporting documentation at least one week prior to the conference to make the conference more efficient and effective. The focus of the Regulatory Conference is to discuss the significance of the finding and not necessarily the root cause(s) or corrective action(s)
associated with the finding. If a Regulatory Conference is held, it will be open for public observation. If you decide to submit only a written response, such submittal should be sent to the NRC within 40 days of your receipt of this letter.
If you choose to send a response, please include your perspective of the significance of the finding along with the related facts and assumptions used to reach your determination.
March 2, 2023 Additionally, your response should be clearly marked as a Response to an Apparent Violation; EA-22-122 and should include for the apparent violation: (1) the reason for the apparent violation or, if contested, the basis for disputing the apparent violation; (2) the corrective steps that have been taken and the results achieved; (3) the corrective steps that will be taken; and (4) the date when full compliance will be achieved. Your response should be submitted under oath or affirmation and may reference or include previously docketed correspondence if the correspondence adequately addresses the required response. Additionally, your response should be sent to the U.S. Nuclear Regulatory Commission, ATTN: Document Control Center, Washington, DC 20555-0001 with a copy to Mr. Louis McKown, U.S. Nuclear Regulatory Commission, Region II, within 40 days of the date of this letter. If an adequate response is not received within the time specified or an extension of time has not been granted by the NRC, the NRC will proceed with its enforcement decision or schedule a Regulatory Conference.
If you decline to request a Regulatory Conference or to submit a written response, you relinquish your right to appeal the final SDP determination, in that by not doing either, you fail to meet the appeal requirements stated in the Prerequisite and Limitation sections of Attachment 2 of NRC Inspection Manual Chapter 0609.
Please contact Mr. Louis J. McKown at 404-997-4545, and in writing, within 10 days from the issue date of this letter to notify the NRC of your intentions. If we have not heard from you within 10 days, we will continue with our significance determination and enforcement decision. The final resolution of this matter will be conveyed in separate correspondence.
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 10 CFR 2.390, Public inspections, exemptions, requests for withholding.
Sincerely, LaDonna B. Suggs, Acting Director Division of Reactor Projects Docket Nos. 05000259 and 05000260 License Nos. DPR-33 and DPR-52
Enclosure:
As stated
Inspection Report
Docket Numbers:
05000259 and 05000260
License Numbers:
Report Numbers:
05000259/2023090 and 05000260/2023090
Enterprise Identifier:
I-2023-090-0000
Licensee:
Tennessee Valley Authority
Facility:
Browns Ferry Nuclear Plant
Location:
Athens, Alabama
Inspection Dates:
January 01, 2023 to February 1, 2023
Inspectors:
N. Karlovich, Resident Inspector
S. Ninh, Senior Project Engineer
K. Pfeil, Resident Inspector
A. Rosebrook, Senior Reactor Analyst
J. Steward, Senior Resident Inspector
Approved By:
Louis J. McKown, II, Chief
Reactor Projects Branch 5
Division of Reactor Projects
SUMMARY
The U.S. Nuclear Regulatory Commission (NRC) continued monitoring the licensees performance by conducting a NRC inspection at Browns Ferry Nuclear Plant, 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
Browns Ferry Unit 1 HPCI Inoperable on July 12, 2022 Cornerstone Significance Cross-Cutting Aspect Report Section Mitigating Systems Preliminary White AV 05000259/2023090-01 Open EA-22-122
[P.2] -
Evaluation 71152S An NRC-identified apparent violation of 10 CFR Part 50, Appendix B, Criterion XVI, was identified for the licensees failure to identify and correct a condition adverse to quality associated with the electric governor remote (EG-R) and remote servo subcomponents. This resulted in the inoperability of the Browns Ferry Unit 1 high pressure coolant injection (HPCI)system on July 12, 2022. Specifically, the licensee failed to promptly identify adverse conditions during the preventive maintenance internal inspection of the EG-R on October 27, 2018, wherein the licensee inspection should have reported observed rust or moisture and initiated a condition report (CR) in accordance with the Section 6.2.5 requirement of Mechanical Preventive Instruction, MPI-0-073-TRB001, HPCI Turbine Preventive Maintenance, Revision 0053.
Additional Tracking Items
Type Issue Number Title Report Section Status URI 05000259/2022003-01 Browns Ferry Unit 1 High Pressure Coolant Injection (HPCI) Inoperable on July 12, 2022 71152S Closed
INSPECTION SCOPES
Inspections were conducted using the appropriate portions of the inspection procedures (IPs) in effect at the beginning of the inspection unless otherwise noted. Currently approved IPs with their attached revision histories are located on the public website at http://www.nrc.gov/reading-rm/doc-collections/insp-manual/inspection-procedure/index.html. Samples were declared complete when the IP requirements most appropriate to the inspection activity were met consistent with Inspection Manual Chapter (IMC) 2515, Light-Water Reactor Inspection Program - Operations Phase. The inspectors reviewed selected procedures and records, observed activities, and interviewed personnel to assess licensee performance and compliance with Commission rules and regulations, license conditions, site procedures, and standards.
INSPECTION RESULTS
Browns Ferry Unit 1 HPCI Inoperable on July 12, 2022 Cornerstone Significance Cross-Cutting Aspect Report Section Mitigating Systems Preliminary White AV 05000259/2023090-01 Open EA-22-122
[P.2] -
Evaluation 71152S An NRC-identified apparent violation of 10 CFR Part 50, Appendix B, Criterion XVI, was identified for the licensees failure to identify and correct a condition adverse to quality associated with the EG-R and remote servo subcomponents. This resulted in the inoperability of the Browns Ferry Unit 1 HPCI system on July 12, 2022. Specifically, the licensee failed to promptly identify adverse conditions during the preventive maintenance internal inspection of the EG-R on October 27, 2018, wherein the licensee inspection should have reported observed rust or moisture and initiated a condition report (CR) in accordance with the Section 6.2.5 requirement of Mechanical Preventive Instruction, MPI-0-073-TRB001, HPCI Turbine Preventive Maintenance, Revision 0053.
Description:
On July 12, 2022, during unit 1 Quarterly HPCI surveillance testing, the governor valve failed to open after operators placed the auxiliary oil pump into service in accordance with 1-SR-3.5.1.7, Section 6.3 Prestartup Trip Checks. The Unit 1 HPCI system had passed its last surveillance test on April 13, 2022. The operators suspended testing following the governor valves failure to open and declared HPCI inoperable.
Licensee troubleshooting and invasive vendor analysis determined that the EG-R and EG-R servo, which controls governor valve position, had bound and seized due to corrosion from unacceptable water contamination of the HPCI control oil. TVA determined that the apparent cause of failure was inadequate proceduralized industry guidance associated with water in HPCI control oil condition monitoring.
After moisture enters the HPCI lubrication and control oil system, it will travel throughout the system via the shaft-driven positive displacement oil pump that circulates oil through the heat exchanger, turbine bearings, and the governor system. If the turbine is equipped with an electric governor as at Browns Ferry that shares the turbine bearing oil system, keeping moisture levels at a minimum is desirable. For governor shared oil systems, once moisture laden oil is in the system, the governor and the remote servo will become contaminated with water. The governor draws oil in upon startup, and the oil remains in the unit until shutdown.
At moisture levels above the water dropout point of the oil usually 0.04-0.05% for most turbine oils, free water will be present after the oil stops flowing and mixing. When free water is present, corrosion will begin, which can clog small orifices and passages affecting governor operation. During empirical studies corrosion was observed in as little as three days where free water was allowed to contact the metal surfaces.
Piping Configuration On March 29, 2013, work order 114560684 was written to route the unit 1 HPCI gland seal leak off lines downward. The work order stated in part, According to the HPCI turbine vendor manual, glands are so arranged that the pressure on the final section is relieved by a leak off connection. Work order 114560684 identified that Excessive back pressure causes leakage, which is a common cause of water in the lubricating oil.
On February 25, 2019, a system engineer added a log note recommending coding the work order corrective critical priority maintenance as blockage in the lines due to steam condensing with the line routed uphill creates the potential for rapidly increasing component degradation. Once the lines are blocked with condensation, steam will impinge the turbine bearing housing and in the long run corrode the EG-R making the governor control system unreliable. On February 26, 2019, the work order was coded corrective low priority maintenance due to its age.
The licensee first classified the Unit 1 HPCI gland seal leak off piping condition as adverse following identification of an adverse rising moisture trend (CR 1729940) from 0.013% on April 14, 2021, to 0.045% on July 16, 2021, to 0.067% on October 14, 2021, in HPCI oil on October 21, 2021. The licensee established a corrective action to implement work order 114560684 during an upcoming outage. Updated condition monitoring standards established by the Terry Turbine Users Group (TTUG) in August 2021, directed immediate cleaning and flushing of the entire oil system on identification of moisture levels above 0.05% with inspection and/or replacement of the EG-R during the next refueling outage.
EG-R Inspection The October 27, 2018, licensee preventive maintenance inspection of the EG-R reported no adverse findings. Identification of EG-R adverse findings, including internal corrosion or moisture contamination, requires initiation of a condition report per the quality related preventive maintenance procedure, HPCI Turbine Preventive Maintenance, MPI-0-073-TRB001, Revision 0053. Even small amounts of corrosion can have substantial adverse impact on governor operation. If found, industry maintenance guidance recommends replacement of the EG-R. On January 5, 2023, the licensee discovered images taken during the unit 1, October 27, 2018, HPCI EG-R inspection in the engineering outage inspection folder. These images clearly showed corrosion and indication of moisture contamination as indicated by orange discoloration beginning on metallic surfaces then extending throughout the EG-R interior. The internal corrosion and moisture contamination went unreported until observed following EG-R failure on July 12, 2022.
Newly Established Industry Guidance In December 2021, Electric Power Research Institute (EPRI) published notes on the August 2021 TTUG meeting in which industry experts reviewing operating experience and empirical data changed the condition monitoring limit for moisture in Terry turbine control oil from 0.5%
to 0.05% by mass. In October 2021, the licensee discovered a rising trend in HPCI control oil moisture with the value exceeding 0.05%. During their apparent cause evaluation, BFN determined that TVA had not been informed of the TTUGs change in guidance in advance of the July 2022 failure.
However, the NRC inspectors discovered a benchmarking report which identified the attendance by the BFN HPCI system engineers of the August 2021 TTUG meeting. While this report did not specifically capture the change in monitoring criteria, it did call out discussions on governor lube oil and the expectation of new industry guidance to be published by EPRI based upon the TTUG meeting. The revised performance criteria went unincorporated into licensee processes following establishment during the August 2021 TTUG meeting and publishing by EPRI in December 2021, until industry peers brought the change to TVAs attention during the Summer 2022 TTUG meeting held after the EG-R failure on July 12, 2022.
Corrective Actions: The licensee's correction actions were to replace the Unit 1 HPCI EG-R, to perform walkdowns of the Unit 2&3 gland seal lines, and to perform EG-R inspections of Unit 2 & 3 HPCI and Unit 3 reactor core isolation cooling system.
Corrective Action References: CRs 1729940, 1789217, and 1827759
Performance Assessment:
Performance Deficiency: The inspectors found that the licensees failure to promptly identify and correct conditions adverse to quality in accordance with their EG-R component condition monitoring were performance deficiencies reasonably within the licensees ability to foresee and prevent.
Specifically, on October 27, 2018, licensee reported no adverse findings during preventive maintenance internal inspection of the unit 1 HPCI EG-R. However, inspection images clearly showed corrosion and indication of moisture contamination based upon orange discoloration on metallic surfaces that extended throughout the EG-R interior. The internal corrosion and moisture contamination went unreported until observed following EG-R failure on July 12, 2022.
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 condition affected the reliability of the Unit 1 HPCI to perform its design basis function.
Significance: The inspectors assessed the significance of the finding using IMC 0609 Appendix A, The Significance Determination Process (SDP) for Findings At-Power. The affected cornerstone was Mitigating Systems, as determined by IMC 0609, Attachment 4, Initial Characterization of Findings. The inspectors screened the performance deficiency using Exhibit 2 of Appendix A and determined a detailed risk evaluation was required because the degraded condition represented a loss of the PRA function of a single train TS for greater than its TS allowed outage time.
RISK ANALYSIS/CONSIDERATIONS A regional Senior Reactor Analyst (SRA) performed a risk assessment in accordance with NRC Inspection manual Chapter 0609 Appendix A. The SRA used SAPHIRE 8 version 8.2.6 and the Browns Ferry Unit 1 SPAR model version 8.80 dated 5/26/2022. The Browns Ferry SPAR models do not contain sequences for fires or internal flooding. Since the licensee has an NFPA 805 fire PRA and modeled internal flooding and seismic in their CAFTA plant risk model, the licensees results for fire, internal flooding and seismic were considered to be best available information.
Assumptions:
1)
Condition exposure time is 48 days.
2)
Condition modelled at a failure to start for the HPCI pump due to the internal corrosion condition.
3)
FLEX credit for internal events was applied.
4)
SPAR model data was used for Internal Events and for Tornado/High Winds events.
5)
Licensee CAFTA model data was used for Internal Flooding Internal Fire, and Seismic events because it was considered to be best available information for these sequences.
6)
No recovery credit was applied since the troubleshooting and repairs took 3 days.
EXPOSURE TIME:
The last successful run of the Unit 1 HPCI system was on April 13, 2022. Therefore, the time period since the last successful run is April 13, 2022, until July 12, 2022, (90 days). Repairs were expected to be completed on July 15, 2022. In accordance with the Risk Assessment Standardization Project (RASP) Manual Volume 1 Volume 1 - Internal Events, for a failure that could have occurred at any time since the component was last operated (e.g., time of actual failure cannot be determined due to the nature of the failure mechanism), the exposure time (T) is equal to one-half of the time period since the last successful functional operation of the component (t/2) plus repair time. This exposure time determination approach is appropriate for standby or periodically operated components that fail due to a degradation mechanism that gradually affects the component during the standby time period. The t/2 period should be considered for the following cases:
- Failure mechanism was caused by nominal environmental conditions (e.g., corrosion, degradation of condensate storage tank floating diaphragm).
T/2 + repair time = 90/2 + 3 days = 48 days DATE OF OCCURRENCE: July 12, 2022.
SAFETY IMPACT: HPCI, a single train safety system, was unable to perform its safety function for an estimated period of 48 days Significant Influence Factor(s): Licenses PRA evaluation results Table 2-1: HPCI Unavailable Results Measure Truncation Base HPCI Delta ICCDP/ICLERP delta (48 days)
U1 CDF (IE)1.00E-12 2.13E-06 1.66E-05 1.45E-05 1.90E-06 U1 CDF (Flood)1.00E-12 1.58E-06 1.34E-05 1.18E-05 1.55E-06 U1 CDF (Fire)1.00E-12 2.90E-05 4.54E-05 1.64E-05 2.15E-06 U1 CDF (Seismic)1.00E-11 5.94E-06 6.28E-06 3.40E-07 4.46E-08 Total:
5.65E-06 U1 LERF (IE)1.00E-13 6.63E-07 1.27E-06 6.07E-07 7.98E-08 U1 LERF (Flood)1.00E-13 3.27E-07 8.73E-07 5.45E-07 7.17E-08 U1 LERF (Fire)1.00E-13 4.58E-06 4.75E-06 1.66E-07 2.19E-08 U1 LERF (Seismic)5.00E-12 4.00E-06 4.52E-06 5.16E-07 6.79E-08 Total:
2.41E-07 Note: Delta/ICCDP/ICLERP values are calculated using full precision and can differ slightly from what would be obtained if using the Base and HPCI values shown in the table.
Due to some of the Browns Ferrys unique mitigating systems such as the emergency high pressure make-up system which has an independent diesel generator backup power supply, these results are reasonable. For similar boiling water reactors (BWRs), the fire and internal flooding results are dominant and are higher risk as expected for this reason.
CALCULATIONS DELTA CDF FOR EXPOSURE TIME 4.75E-6 EXTERNAL EVENTS CONSIDERATIONS Internal Events was 1.00 E-6 so external events must be considered.
Fire: 1.55E-6 Flood: 2.15E-6 Seismic: 4.46E-8 Tornado/Hurricane/High Wind: 2.93E-10 LARGE EARLY RELEASE FREQUENCY IMPACT The licensees PRA evaluation calculated change in LERF to be 2.41E-7. This corresponds to a WHITE LERF finding.
Since the licensee has a Phase II PRA, this is considered best available information in lieu of IMC 0609 Appendix Hs more qualitative approach.
UNCERTAINTY ANALYSIS:
The NRCs SPAR model for BFN does not include internal fire or internal flooding sequences.
As a result, the licensees CAFTA model was used and considered best available information for internal fire, internal flooding and seismic sequence results. These results were qualitatively compared with information from risk information provided in licensee amendment requests (such as the NFPA-805 LAR) and SPAR model data from other NFPA-805 BWR plants.
For internal event results of the licensees CAFTA model and the NRC SPAR model, versions 8.80 and 8.61 were all compared and considered.
CAFTA: 1.90E-6 SPAR Version 8.61 : 1.57E-6 SPAR Version 8.80 : 1.0E-6 SENSITITIVITY EVALUATION:
Because the licensee Data is being used as best available information, it is not feasible to do a sensitivity analysis as Internal Fire and Internal flooding are 2 of the 3 dominate initiators.
However, for Internal Events, a sensitivity analysis was performed by comparing internal event results of the licensees CAFTA model and the NRC SPAR model versions 8.80 and 8.61.
CAFTA: 1.90E-6 SPAR Version 8.61 : 1.57E-6 SPAR Version 8.80 : 1.0E-6 The SRA chose to use the NRC SPAR model for Internal Events and Tornado, Hurricane, and High Winds, but the other models provide sensitivity information.
CONCLUSIONS/RECOMMENDATIONS Preliminary White due to delta CDF between 4.75 E-6 and 5.65 E-6 and delta LERF 2.41E-7, both of which correspond to a finding of low to moderated safety significance (WHITE).
Cross-Cutting Aspect: P.2 - Evaluation: The organization thoroughly evaluates issues to ensure that resolutions address causes and extent of conditions commensurate with their safety significance. Specifically, TVA did not thoroughly investigate the conditions observed during the October 17, 2018, EG-R inspection, the changes in condition monitoring introduced during 2021 TTUG meeting, or the safety significance of these conditions as they relate to the July 12, 2022 failure.
Enforcement:
Violation: 10 CFR 50, Appendix B, Criterion XVI requires, in part, measures shall be established to assure that conditions adverse to quality, such as failures, malfunctions, deficiencies, deviations, defective material and equipment, and nonconformances are promptly identified and corrected.
Section 10.2.2, Corrective Action for Adverse Conditions of the Nuclear Quality Assurance Plan (NQAP) (Quality Assurance Program Description), TVA-NQA-PLN89-A, Rev.0040, states in part that TVA Nuclear and onsite non-nuclear service organizations performing quality-related activities at nuclear facilities shall promptly identify and resolve adverse conditions.
Section 5 of NPG-SPP-22.300.1, Corrective Action Program (BFN Only), Rev. 0000, defines that Conditions Adverse to Quality (CAQ) is a condition associated with a structure, system, component or program that is in-scope of the Nuclear Quality Assurance Plan (NQAP). The HPCI system is a safety-related system and is in the scope of the NQAP.
Mechanical Preventive Instruction, MPI-0-073-TRB001, High Pressure Coolant Injection (HPCI) Turbine Preventive Maintenance, Revision 0053, Section 6.2.5, states, in part, that internal corrosion or moisture contamination requires initiation of a condition report.
Contrary to the above, from October 27, 2018, to July 12, 2022, the licensee failed to promptly identify and correct the condition adverse to quality associated with the EG-R and remote servo subcomponents. Specifically, the licensee failed to promptly document and correct adverse conditions during the preventive maintenance internal inspection of the EG-R on October 27, 2018, wherein the licensee inspection identified rust and moisture, but failed to initiate a required CAQ CR in accordance with MPI-0-073-TRB001 and TVA-NQA-PLN89-A.
Enforcement Action: This violation is being treated as an apparent violation pending a final significance (enforcement) determination.
EXIT MEETINGS AND DEBRIEFS
The inspectors verified no proprietary information was retained or documented in this report.
On February 13, 2023, the inspectors presented the NRC inspection results to Chris Vaughn, Site Licensing Manager, Browns Ferry Nuclear Plant and other members of the licensee staff.
DOCUMENTS REVIEWED
Inspection
Procedure
Type
Designation
Description or Title
Revision or
Date
1474426,
29940
Increasing trends in the Unit 1 HPCI Oil sample
2/08/2022
1552443
Layout and sketch piping and fitting to obtain required slope
for the Unit 1 HPCI Gland Seal Leakoff Lines
09/26/2019
1606144
TTUG Benchmarking Trip Report (Virtual)
09/14/2021
1606144
Benchmark NSSS Engineering EPRI TTUG 2020 and 2021
05/05/2020
1630475
08/14/2020
1656131
Revise MPI-0-073-TRB001
2/07/2020
1789217
Human Performance Alert initiated by NSSS Systems
Engineering
11/2022
1796362
U1 HPCI Lube Oil Tank at Minimum Level
08/15/2022
1809748
WO 114560684 - Reroute of Unit 1 HPCI gland seal piping
cannot be performed as planned - requires an ECP
10/16/2022
23281
Site Licensing Learnings from July 2022 U1 HPCI EGR
Corrosion Binding Event
2/14/2022
704497
Problem Evaluation Report (PER) Summary: Unit 2 HPCI
Gland Seal Leakoff Lines need to be routed downward
03/31/2013
L2 for CR
1789217
HPCI L2 Evaluation
10/10/2022
Corrective Action
Documents
L2 for CR
1789217
Level 2 Evaluation Report for U1 HPCI Turbine Control Valve
Failed to Open
Rev 0
Corrective Action
Documents
Resulting from
Inspection
27759
U1R12 Rust in HPCI EGR identified during RO Inspection
Retroactively
01/07/2023
HPCI EGR Level 2 Report Timelines and Moisture Content
Data
2/08/2022
EPRI Nuclear Maintenance Applications (NMAC) December
21 Lube Notes
2/2021
703905
Unit 1 HPCI Gland Seal Leakoff Lines Need to be routed
downward
03/29/2013
Miscellaneous
95-021-00
Hope Creek Generating Station Licensee Event Report titled
10/20/1995
Inspection
Procedure
Type
Designation
Description or Title
Revision or
Date
"Unplanned Inoperability of the High Pressure Coolant
Injection System due to Water Contamination of the
Lubricating System"
ACMP 1790363
U1 HPCI EGR Lubrication
07/20/22
BFN-VTD-T147-
0440
Unit 1 Terry Turbine Steam Turbine CO. Installation
Rev 0
BFN-VTD-T147-
0490
Unit 1 Terry Turbine Steam Turbine CO. Recommended Fits
and Allowance (Governing Oil Relay and Linkage System)
Rev 0
BFN-VTD-T147-
0530
U-1 Terry Steam Turbine Co. Lubrication System
Rev 0
BFN-VTD-W290-
480
Unit 1 Woodward Governor CO. Installation and Operation of
EG-3C and EG-R Actuators Terry Model CS HPCI Turbine
Operation
Rev 0
During U1 HPCI rated flow test, the governor valve failed to
operate as expected.
07/12/2022
G-94
General Engineering Specification G-94 Piping Installation,
Modification and Maintenance
03/31/2000
Licensee Event
Report 2007-007-
Edwin I. Hatch Unit 2 High Pressure Coolant Injection
System Inoperable due to clogged valve causing water
intrusion into the oil system
0713/2007
Manual 25071
Woodward Oils for Hydraulic Controls
Rev J
Operability
Evaluations
1789217
Past Operability Evaluation of the impact that the Unit 1
HPCI EGR condition had on HPCI Operability leading up to
the surveillance test on July 12, 2022.
08/03/2022
MCI-0-073-
TRB001
High Pressure Coolant Injection (HPCI) Turbine Preventive
Maintenance
Rev 52
MPI-0-073-
TRB001
High Pressure Coolant Injection (HPCI) Turbine Preventive
Maintenance
Rev 56
MPI-0-073-
TRB001
High Pressure Coolant Injection (HPCI) Turbine Preventive
Maintenance
Rev 53
MPI-0-073-
TRB001
High Pressure Coolant Injection (HPCI) Turbine Preventive
Maintenance
Rev 58
Procedures
NEDP-27
Past Operability Evaluations
Rev 7
Inspection
Procedure
Type
Designation
Description or Title
Revision or
Date
NPG-SPP -07.2.8
Outage Scope Control
Rev 13
NPG-SPP-01.15
Service Request Initial Review
03/16/2011
NPG-SPP-03.1
Corrective Action Program
03/08/2013
NPG-SPP-06.1
Work Order Process
Rev 12
NPG-SPP-07.1.4
Work Management Prioritization - On Line
Rev 24
Work Orders
119022899
Perform scheduled 2 YR RO Inspection on HPCI, 1-TRB-
073-0054, and associated equipment
10/31/2018