IR 05000341/2012005
| ML13028A454 | |
| Person / Time | |
|---|---|
| Site: | Fermi  |
| Issue date: | 01/28/2013 |
| From: | Jamnes Cameron NRC/RGN-III/DRP/B6 |
| To: | Plona J DTE Electric Company |
| References | |
| IR-12-005 | |
| Download: ML13028A454 (43) | |
Text
nuary 28, 2013
SUBJECT:
FERMI POWER PLANT, UNIT 2 - NRC INTEGRATED INSPECTION REPORT 05000341/2012005
Dear Mr. Plona:
On December 31, 2012, the U.S. Nuclear Regulatory Commission (NRC) completed an integrated inspection at your Fermi Power Plant, Unit 2. The enclosed inspection report documents the inspection results which were discussed on January 8, 2013, with Mr. K. Scott, Plant Manager, and other members of your staff.
The inspection examined activities conducted under your license as they relate to safety and compliance with the Commissions rules and regulations and with the conditions of your license.
The inspectors reviewed selected procedures and records, observed activities, and interviewed personnel.
Based on the results of this inspection, two self-revealed findings of very low safety significance (Green) were identified. One of the findings involved a violation of NRC requirements.
Additionally, two licensee-identified violations are listed in Section 4OA7 of this report.
However, because of their very low safety significance, and because the issues were entered into your corrective action program, the NRC is treating the issues as non-cited violations (NCVs) in accordance with Section 2.3.2 of the NRC Enforcement Policy.
If you contest the violation or significance of these NCVs, 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 a copy to the Regional Administrator, U.S. Nuclear Regulatory Commission - Region III, 2443 Warrenville Road, Suite 210, Lisle, IL 60532-4352; the Director, Office of Enforcement, U.S. Nuclear Regulatory Commission, Washington, DC 20555-0001; and the Resident Inspector Office at the Fermi Power Plant. If you disagree with the cross-cutting aspect assigned to any finding 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 Regional Administrator, Region III, and the NRC Resident Inspector at the Fermi Power Plant.
In accordance with 10 CFR 2.390 of the NRC's "Rules of Practice," a copy of this letter, its enclosure, and your response (if any) will be available electronically for public inspection in the NRC Public Document Room or from the Publicly Available Records System (PARS)
component of NRC's Agencywide Document Access and Management System (ADAMS).
ADAMS is accessible from the NRC Website at http://www.nrc.gov/reading-rm/adams.html (the Public Electronic Reading Room).
Sincerely,
/RA/
Jamnes L. Cameron, Chief Branch 6 Division of Reactor Projects Docket No. 50-341 License No. NPF-43
Enclosure:
Inspection Report 05000341/2012005 w/Attachment: Supplemental Information
REGION III==
Docket No: 50-341 License No: NPF-43 Report No: 05000341/2012005 Licensee: Detroit Edison Company Facility: Fermi Power Plant, Unit 2 Location: Newport, MI Dates: October 1 through December 31, 2012 Inspectors: R. Morris, Senior Resident Inspector R. Jones, Resident Inspector J. Beavers, Emergency Preparedness Inspector M. Bielby, Senior Operations Engineer, Lead Inspector T. Briley, Reactor Engineer B. Kemker, Senior Resident Inspector, Clinton J. Nance, Resident Inspector, Perry P. Smagacz, Reactor Engineer D. Szwarc, Reactor Inspector M. Jones, Jr., Reactor Engineer Approved by: J. Cameron, Chief Branch 6 Division of Reactor Projects Enclosure
SUMMARY OF FINDINGS
Inspection Report 05000341/2012005; 10/01/2012 - 12/31/2012; Fermi Power Plant, Unit 2;
Maintenance Effectiveness and Follow-Up of Events.
This report covers a 3-month period of inspection by resident inspectors and announced baseline inspections by regional inspectors. Two Green findings were identified by the inspectors. One of the findings was considered a non-cited violation (NCV) of NRC regulations. The significance of inspection findings is indicated by their color (i.e., greater than Green, or Green, White, Yellow, Red) and determined using Inspection Manual Chapter (IMC) 0609, Significance Determination Process (SDP) dated June 2, 2011. Cross-cutting aspects are determined using IMC 0310, Components Within the Cross-Cutting Areas, dated October 28, 2011. All violations of NRC requirements are dispositioned in accordance with the NRCs Enforcement Policy dated June 7, 2012. The NRC's program for overseeing the safe operation of commercial nuclear power reactors is described in NUREG-1649, Reactor Oversight Process Revision 4, dated December 2006.
NRC-Identified
and Self-Revealed Findings
Cornerstone: Initiating Events
- Green.
A self-revealed finding of very low safety significance and associated NCV of Technical Specification 5.4.1.a was identified for the licensees failure to establish and implement procedures recommended by Regulatory Guide 1.33, Revision 2,
Appendix A, February 1978. Specifically, the licensee failed to control the three factors identified by the root cause evaluation team within their refueling outage (RF)-15 south reactor feed pump turbine (SRFPT) overhaul maintenance instructions and post-maintenance testing instructions; and within the operating procedures for the reactor feed pumps during synchronizing the main generator to the electrical grid following recovery from repairs performed on main unit transformer 2B. The south reactor feed pump (SRFP) catastrophically failed, and as a result, the reactor was shut down because of decreasing condenser vacuum.
The inspectors determined the failure to control the presence of three factors in concert:
(1) no turbine diaphragm alignment with tight clearances; (2) automatic admission of steam with challenging thermal properties; and (3) less than adequate post-maintenance testing, was a performance deficiency that required evaluation using the SDP. The inspectors determined this finding was more than minor because it was associated with the equipment performance attribute of the Initiating Events Cornerstone and impacted the cornerstone objective of limiting the likelihood of those events that upset plant stability. This finding was determined to be of very low safety significance because, following IMC 0609, Table 4a, Characterization Worksheet for Initiating Events,
Mitigating Systems, and Barrier Integrity Cornerstones, the inspectors concluded the finding did not require quantitative assessment. Therefore, the finding was determined to be of very low safety significance. This finding has a cross-cutting aspect in the area of Human Performance, Work Practices, supervisory and management oversight aspect because the licensee failed to appropriately oversee the overhaul of the SRFPT by a vendor, and the post maintenance testing and operation of the SRFPT during and after RF-15 (H.4 (c)). (Section 4OA3.1)
Cornerstone: Mitigating Systems
- Green.
A finding of very low safety significance was self-revealed for failing to adequately inspect and identify, and then correct severe degradation of the motor operator for E4150F002 [HPCI turbine steam supply inboard containment isolation valve], which failed on July 23, 2012, when operators were attempting to place the high pressure coolant injection (HPCI) system into standby. The failure analysis of the motor identified the severe degradation. The apparent cause evaluation team identified three apparent and contributing causes for the severe degradation: first, prolonged moisture from steam leaks or other water sources; second, improper end ring coatings; and third, failing to identify a degraded condition during a video probe inspection.
The inspectors determined the failure to adequately inspect and identify, and then correct severe degradation of the motor operator for E4150F002 was a performance deficiency that required an SDP evaluation. The inspectors determined this finding was more than minor because it was associated with the configuration control attribute of the Mitigating Systems Cornerstone and impacted the cornerstone objective of ensuring the capability of systems to prevent undesirable consequences (i.e., core damage). This finding was determined to be of very low safety significance because, following IMC 0609, Appendix E, Table 4a, Characterization Worksheet for Initiating Events,
Mitigating Systems, and Barrier Integrity Cornerstones, all questions were answered no. Therefore, the finding was determined to be of very low safety significance (Green).
This finding has a cross-cutting aspect in the area of Problem Identification and Resolution, Corrective Action Program, appropriate corrective actions aspect because the licensee failed to adequately inspect and identify, and then correct severe degradation of the motor operator for E4150F002 (P.1 (d)). (Section 1R12.1)
Licensee-Identified Violations
Two violations of very low safety significance that were identified by the licensee have been reviewed by inspectors. Corrective actions planned or taken by the licensee have been entered into the licensees corrective action program. These violations and corrective action tracking numbers are listed in Section 4OA7 of this report.
REPORT DETAILS
Summary of Plant Status
Fermi Unit 2 entered the inspection period at 68 percent power with one feedwater pump operable. This is the maximum allowed power with one feedwater pump operating. A manual reactor scram due to hydrogen leakage into the main generator stator water cooling system occurred on November 7, 2012. Startup commenced on December 31, 2012, and the unit was off-line at 8 percent power at the end of the inspection period.
REACTOR SAFETY
Cornerstones: Initiating Events, Mitigating Systems, Barrier Integrity, and Emergency Preparedness
1R01 Adverse Weather Protection
.1 Winter Seasonal Readiness Preparations
a. Inspection Scope
The inspectors conducted a review of the licensees preparations for winter conditions to verify the plants design features and implementation of procedures were sufficient to protect mitigating systems from the effects of adverse weather. Documentation for selected risk-significant systems was reviewed to ensure these systems would remain functional when challenged by inclement weather. During the inspection, the inspectors focused on plant specific design features and the licensees procedures used to mitigate or respond to adverse weather conditions. Additionally, the inspectors reviewed the Updated Final Safety Analysis Report (UFSAR) and performance requirements for systems selected for inspection, and verified operator actions were appropriate as specified by plant specific procedures. Cold weather protection, such as heat tracing and area heaters, was verified to be in operation where applicable. The inspectors also reviewed corrective action program items to verify the licensee was identifying adverse weather issues at an appropriate threshold and entering them into their corrective action program in accordance with station corrective action procedures. Specific documents reviewed during this inspection are listed in the Attachment to this report. The inspectors reviews focused specifically on the following plant systems due to their risk significance or susceptibility to cold weather issues:
- Cold weather preparations and a walkdown prior to high winds from tropical storm Sandy.
This inspection constituted one winter seasonal readiness preparations sample as defined in Inspection Procedure (IP) 71111.01-05.
b. Findings
No findings were identified.
1R04 Equipment Alignment
.1 Quarterly Partial System Walkdowns
a. Inspection Scope
The inspectors performed partial system walkdowns of the following risk-significant systems:
- Residual heat removal (RHR) mechanical draft cooling tower system;
- Division 2 emergency equipment cooling water (EECW); and
- Non-interruptible Air Supply (NIAS).
The inspectors selected these systems based on their risk significance relative to the Reactor Safety Cornerstones at the time they were inspected. The inspectors attempted to identify any discrepancies that could impact the function of the system and, therefore, potentially increase risk. The inspectors reviewed applicable operating procedures, system diagrams, UFSAR, Technical Specification (TS) requirements, outstanding work orders, condition reports, and the impact of ongoing work activities on redundant trains of equipment in order to identify conditions that could have rendered the systems incapable of performing their intended functions. The inspectors also walked down accessible portions of the systems to verify system components and support equipment were aligned correctly and operable. The inspectors examined the material condition of the components and observed operating parameters of equipment to verify there were no obvious deficiencies. The inspectors also verified the licensee had properly identified and resolved equipment alignment problems that could cause initiating events or impact the capability of mitigating systems or barriers and entered them into the corrective action program with the appropriate significance characterization. Documents reviewed are listed in the Attachment to this report.
These activities constituted three partial system walkdown samples as defined in IP 71111.04-05.
b. Findings
No findings were identified.
.2 Semi-Annual Complete System Walkdown
a. Inspection Scope
On October 6, 2012, the inspectors performed a complete system alignment inspection of the main feedwater pump electrical and instruments and controls after SRFPT isolation to verify the functional capability of the system. This system was selected because it was considered risk significant in the licensees probabilistic risk assessment.
The inspectors walked down the system to review mechanical and electrical equipment lineups; electrical power availability; system pressure and temperature indications, as appropriate; component labeling; component lubrication; component and equipment cooling; hangers and supports; operability of support systems; and to ensure ancillary equipment or debris did not interfere with equipment operation. A review of a sample of past and outstanding work orders was performed to determine whether any deficiencies significantly affected the system function. In addition, the inspectors reviewed the corrective action program database to ensure system equipment alignment problems were being identified and appropriately resolved. Documents reviewed are listed in the to this report.
These activities constituted one complete system walkdown sample as defined in IP 71111.04-05.
b. Findings
No findings were identified.
1R05 Fire Protection
.1 Routine Resident Inspector Tours
a. Inspection Scope
The inspectors conducted fire protection walkdowns which were focused on availability, accessibility, and the condition of firefighting equipment in the following risk-significant plant areas:
- RHR/emergency diesel generator (EDG) building, division 2 side;
- Auxiliary building, fifth floor, standby gas treatment, division 1 and 2;
- Reactor building, sub-basement and basement, division 2 core spray;
- Reactor building, second floor, mezzanine; and
- Reactor building, first floor, steam tunnel.
The inspectors reviewed areas to assess if the licensee had implemented a fire protection program that adequately controlled combustibles and ignition sources within the plant, effectively maintained fire detection and suppression capability, maintained passive fire protection features in good material condition, and implemented adequate compensatory measures for out-of-service, degraded or inoperable fire protection equipment, systems, or features in accordance with the licensees fire plan. The inspectors selected fire areas based on their overall contribution to internal fire risk as documented in the plants Individual Plant Examination of External Events with later additional insights, their potential to impact equipment which could initiate or mitigate a plant transient, or their impact on the plants ability to respond to a security event. Using the documents listed in the Attachment to this report, the inspectors verified fire hoses and extinguishers were in their designated locations and available for immediate use; fire detectors and sprinklers were unobstructed; transient material loading was within the analyzed limits; and fire doors, dampers, and penetration seals appeared to be in satisfactory condition. The inspectors also verified minor issues identified during the inspection were entered into the licensees corrective action program. Documents reviewed are listed in the Attachment to this report.
These activities constituted five quarterly fire protection inspection samples as defined in IP 71111.05-05.
b. Findings
No findings were identified.
1R06 Flooding
.1 Underground Vaults
a. Inspection Scope
The inspectors selected underground bunkers/manholes subject to flooding that contained cables whose failure could disable risk-significant equipment. The inspectors determined the cables were not submerged, splices were intact, and appropriate cable support structures were in place. In those areas where dewatering devices were used, such as a sump pump, the device was operable and level alarm circuits were set appropriately to ensure the cables would not be submerged. In those areas without dewatering devices, the inspectors verified drainage of the area was available, or the cables were qualified for submergence conditions. The inspectors also reviewed the licensees corrective action documents with respect to past submerged cable issues identified in the corrective action program to verify the adequacy of the corrective actions. The inspectors performed a walkdown of the following underground bunkers/manholes subject to flooding:
- The east security cable manholes and the west RHR/EDG manholes which were potentially impacted by the November 1 oil spill response and storm drain flushing.
Specific documents reviewed during this inspection are listed in the Attachment to this report.
This inspection constituted one underground vaults sample as defined in IP 71111.06-05.
b. Findings
No findings were identified.
1R11 Licensed Operator Requalification Program
.1 Resident Inspector Quarterly Review of Licensed Operator Requalification
a. Inspection Scope
On November 20, 2012, the inspectors observed a crew of licensed operators in the plants simulator during licensed operator requalification training to verify operator performance was adequate, evaluators were identifying and documenting crew performance problems, and training was being conducted in accordance with licensee procedures. The inspectors evaluated the following areas:
- licensed operator performance;
- crews clarity and formality of communications;
- ability to take timely actions in the conservative direction;
- prioritization, interpretation, and verification of annunciator alarms;
- correct use and implementation of abnormal and emergency procedures;
- control board manipulations;
- oversight and direction from supervisors; and
- ability to identify and implement appropriate TS actions and Emergency Plan actions and notifications.
The crews performance in these areas was compared to pre-established operator action expectations and successful critical task completion requirements. Documents reviewed are listed in the Attachment to this report.
This inspection constituted one quarterly licensed operator requalification program simulator sample as defined in IP 71111.11 and satisfied the inspection program requirement for the resident inspectors to observe a portion of an in-progress annual requalification operating test during a training cycle in which it was not observed by the NRC during the biennial portion of this IP.
b. Findings
No findings were identified.
.2 Resident Inspector Quarterly Observation of Heightened Activity or Risk
a. Inspection Scope
On November 1, 2012, the inspectors observed operators perform procedure 42.302.04, Division 2 4160V bus 65E/13EC, Undervoltage Logic System Functional. On November 7, 2012, the inspectors observed operators perform scram abnormal operating procedure following a manual scram due to increasing hydrogen gas leakage observed in the main generator. These were activities that required heightened awareness or were related to increased risk. The inspectors evaluated the following areas:
- licensed operator performance;
- crews clarity and formality of communications;
- ability to take timely actions in the conservative direction;
- prioritization, interpretation, and verification of annunciator alarms;
- correct use and implementation of procedures;
- control board and equipment manipulations;
- oversight and direction from supervisors; and
- ability to identify and implement appropriate TS actions.
The performance in these areas was compared to pre-established operator action expectations, procedural compliance and task completion requirements. Documents reviewed are listed in the Attachment to this report.
These inspections constituted one quarterly licensed operator heightened activity/risk sample as defined in IP 71111.11.
b. Findings
No findings were identified.
.3 Annual Operating Test Results
a. Inspection Scope
The inspectors reviewed the overall pass/fail results of the Annual Operating Test, administered by the licensee from November 5 through December 7, 2012, required by 10 CFR 55.59(a). The results were compared to the thresholds established in IMC 0609, Appendix I, Human Performance Operator Requalification Significance Determination Process," to assess the overall adequacy of the licensees operator
+requalification training program to meet the requirements of 10 CFR 55.59.
This inspection constitutes one annual licensed operator requalification inspection sample as defined in IP 71111.11-05.
b. Findings
No findings were identified.
1R12 Maintenance Effectiveness
.1 Routine Quarterly Evaluations
a. Inspection Scope
The inspectors evaluated degraded performance issues involving the following risk-significant systems:
- A7100 primary containment isolation;
- Maintenance Rule periodic a(3) evaluation; and
The inspectors reviewed events such as where ineffective equipment maintenance had or could have resulted in valid or invalid automatic actuations of engineered safeguards systems and independently verified the licensee's actions to address system performance or condition problems in terms of the following:
- implementing appropriate work practices;
- identifying and addressing common cause failures;
- scoping of systems in accordance with 10 CFR 50.65(b) of the maintenance rule;
- characterizing system reliability issues for performance;
- charging unavailability for performance;
- trending key parameters for condition monitoring;
- ensuring 10 CFR 50.65(a)(1) or (a)(2) classification or re-classification; and
- verifying appropriate performance criteria for structures, systems, and components/functions classified as (a)(2), or appropriate and adequate goals and corrective actions for systems classified as (a)(1).
The inspectors assessed performance issues with respect to the reliability, availability, and condition monitoring of the system. In addition, the inspectors verified maintenance effectiveness issues were entered into the corrective action program with the appropriate significance characterization. Documents reviewed are listed in the Attachment to this report.
This inspection constituted two quarterly maintenance effectiveness samples as defined in IP 71111.12-05, and a continuation of one quarterly maintenance effectiveness sample initiated and counted as a sample in the third quarter (NRC Inspection Report 05000341/2012-004).
b. Findings
Introduction:
A finding of very low safety significance (Green) was self-revealed for failing to adequately inspect and identify, and then correct severe degradation of the motor operator for E4150F002, which failed on July 23, 2012, when operators were attempting to place the HPCI system into standby. The failure analysis of the motor identified severe degradation. The apparent cause evaluation (ACE) team identified three apparent and contributing causes for the severe degradation: first, prolonged moisture from steam leaks or other water sources; second, improper end ring coatings; and third, failing to identify a degraded condition during a video probe inspection.
Description:
On July 23, 2012, during plant startup operators were unable to place the HPCI system into standby due to the failure of E4150F002, the HPCI turbine steam supply inboard containment isolation valve. The failure was determined to be caused by an electrical failure of the motor operator. The failure was due to a buildup of galvanic corrosion between the opposite drive end and the rotor body interface which caused the shorting ring to deflect radially outwards and eventually allow the fins to make contact with the stator windings during operation. The failure analysis attributed the general and galvanic corrosion observed to have been caused by prolonged exposure to high temperatures and high humidity, along with the potential introduction of moisture through the T-drains.
This motor had a magnesium alloy rotor, which had been the subject of previous NRC Information Notices 2006-26 and 2008-20. The apparent cause evaluation team identified four mechanisms which had been responsible for other magnesium rotor motor failures:
- (1) prolonged moisture from steam leaks or other water sources;
- (2) improper end ring coatings;
- (3) failure to identify a degraded condition during a video probe inspection; and
- (4) thermal stresses due to excessive stroking or overloading. The team concluded the apparent cause of this motor failure was mechanism (1), prolonged moisture from steam leaks or other water sources. Packing leakage had been noted during the reactor pressure valve hydrostatic test conducted earlier this year. The leakage had been reviewed and accepted by the Leakage Review Board. Further, condensation had been observed during inspections performed as part of the troubleshooting inspections performed to determine the cause of the failure.
In addition, mechanisms
- (2) and
- (3) were identified as contributing causes of this failure.
Mechanism (2), improper end ring coatings was possible. This valve motor had been procured from Commonwealth Edison in 1994. No inspections were performed until a video probe inspection was performed in 2009 using Boiling Water Reactor (BWR)
Owners Group guidelines, and some blistering was noted. Since this could have resulted from end ring coating defects, the ACE team concluded this was a contributing cause.
Further, the evaluation team assigned a contributing cause to mechanism (3), failure to identify a degraded condition during a video probe inspection. The valve was inspected in 2009 using a video probe. Some degradation was observed and the next inspection was scheduled for RF-17 (or approximately 6 years). The BWR Owners Group guidelines TP-09-005 suggested 10 years between inspections unless degradation is observed, and then recommended a frequency of 2 years for the subsequent inspection.
Had the 2 years recommended in the Owners Group guidance been used, the inspection would have been scheduled for 2011 and may have detected the extent of corrosion and blistering observed in the failure analysis report, and the motor could have been repaired or replaced prior to the July failure.
Analysis:
The inspectors determined the failure to adequately inspect and identify, and then correct severe degradation of the motor operator for E4150F002 was a performance deficiency that required an SDP evaluation. The inspectors determined this finding was more than minor because it was associated with the configuration control attribute of the Mitigating Systems Cornerstone and impacted the cornerstone, objective of ensuring the capability of systems to prevent undesirable consequences, i.e., core damage. This finding was determined to be of very low safety significance because, following IMC 0609, Appendix E, Table 4a, Characterization Worksheet for Initiating Events, Mitigating Systems, and Barrier Integrity Cornerstones, all questions were answered no. Therefore, the finding was determined to be of very low safety significance (Green).
This finding has a cross-cutting aspect in the area of Problem Identification and Resolution, Corrective Action Program, appropriate corrective actions aspect because the licensee failed to adequately inspect and identify, and then correct severe degradation of the motor operator for E4150F002 (P.1 (d)).
Enforcement:
No violation of NRC requirements was identified for this performance deficiency. Failure of E4150F002 (FIN 05000341/2012005-01).
1R13 Maintenance Risk Assessments and Emergent Work Control
.1 Maintenance Risk Assessments and Emergent Work Control
a. Inspection Scope
The inspectors reviewed the licensee's evaluation and management of plant risk for the maintenance and emergent work activities affecting risk-significant and safety-related equipment listed below to verify the appropriate risk assessments were performed prior to removing equipment for work:
- Risk during reactor water cleanup area and nonregenerative heat exchanger discharge temperature functional test; logic functional for division 2 EDG emergency start and auto trip/bypass circuits; turbine building heating ventilation and air conditioning outage; mechanical draft cooling tower fan coordinated manual control switch repair; and EDG 14 jacket cooling pump seal replacement;
- Risk during EDG 11 safety system outage;
- Risk during Equipment Out Of Service calculation for division 1 RHR valve position indication verification test and low pressure coolant injection pump and valve surveillance; risk during bus 65E undervoltage and EDG 13 surveillance; high winds expected for tropical storm Sandy; integrated plant computer system cyber-security modification; division 2 EECW maintenance; bus 65E breaker E9 planned maintenance; and
- Risk during reactor shutdown to mode 4.
These activities were selected based on their potential risk significance relative to the Reactor Safety Cornerstones. As applicable for each activity, the inspectors verified risk assessments were performed as required by 10 CFR 50.65(a)(4) and were accurate and complete. When emergent work was performed, the inspectors verified the plant risk was promptly reassessed and managed. The inspectors reviewed the scope of maintenance work, discussed the results of the assessment with the licensee's probabilistic risk analyst or shift technical advisor, and verified plant conditions were consistent with the risk assessment. The inspectors also reviewed TS requirements and walked down portions of redundant safety systems, when applicable, to verify risk analysis assumptions were valid and applicable requirements were met.
Specific documents reviewed during this inspection are listed in the Attachment to this report.
These maintenance risk assessments and emergent work control activities constituted four samples as defined in IP 71111.13-05.
b. Findings
No findings were identified.
1R15 Operability Determinations and Functional Assessments
.1 Operability Evaluations
a. Inspection Scope
The inspectors reviewed the following issues:
- Corrective action and resolution document (CARD) 12-25847, Main Unit Transformer 2B Oil Leak;
- CARD 12-27504, Seismic Analysis on Panel H11P903; and
- CARD 12-30194, Workmanship Quality Issues Noted in Control Rod Drive Mechanisms during Offsite Inspection.
The inspectors selected these potential operability issues based on the risk significance of the associated components and systems. The inspectors evaluated the technical adequacy of the evaluations to ensure TS operability was properly justified and the subject component or system remained available such that no unrecognized increase in risk occurred. The inspectors compared the operability and design criteria in the appropriate sections of the TS and UFSAR to the licensees evaluations to determine whether the components or systems were operable. Where compensatory measures were required to maintain operability, the inspectors determined whether the measures in place would function as intended and were properly controlled. The inspectors determined, where appropriate, compliance with bounding limitations associated with the evaluations. Additionally, the inspectors reviewed a sampling of corrective action documents to verify the licensee was identifying and correcting any deficiencies associated with operability evaluations. Documents reviewed are listed in the to this report.
This operability inspection constituted four samples as defined in IP 71111.15-05.
b. Findings
No findings were identified.
1R18 Plant Modifications
.1 Plant Modifications
a. Inspection Scope
The inspectors reviewed the following modifications:
- EDP-36982, South Reactor Feed Pump/Turbine (SRFPT) Mechanical Isolations,
- EDP-36984, SRFPT Electrical and I&C Isolations, and 50.59 evaluation.
This inspection was a continuation from NRC Inspection Report 05000341/2012-004; further inspection is documented under Section 4OA2.5. This does not constitute a sample as defined in IP 71111.18-05.
b. Findings
No findings were identified.
1R19 Post-Maintenance Testing
.1 Post-Maintenance Testing
a. Inspection Scope
The inspectors reviewed the following post-maintenance (PM) activities to verify procedures and test activities were adequate to ensure system operability and functional capability:
- Control rod 58-43 friction testing;
- Work Order (WO) 35128354, Division 2 EECW Make-up Pump Discharge Check Valve Failed;
- WO 35662332, Reactor Building 1, Steam Tunnel Blowout Panel Seal Repair; and
- Reactor cooling system hydro after control rod drive mechanism replacement.
These activities were selected based upon the structure, system, or component's ability to impact risk. The inspectors evaluated these activities for the following (as applicable):
the effect of testing on the plant had been adequately addressed; testing was adequate for the maintenance performed; acceptance criteria were clear and demonstrated operational readiness; test instrumentation was appropriate; tests were performed as written in accordance with properly reviewed and approved procedures; equipment was returned to its operational status following testing (temporary modifications or jumpers required for test performance were properly removed after test completion); and test documentation was properly evaluated. The inspectors evaluated the activities against TSs, the UFSAR, 10 CFR Part 50 requirements, licensee procedures, and various NRC generic communications to ensure the test results adequately ensured the equipment met the licensing basis and design requirements. In addition, the inspectors reviewed corrective action documents associated with post-maintenance tests to determine whether the licensee was identifying problems and entering them in the corrective action program and that the problems were being corrected commensurate with their importance to safety. Documents reviewed are listed in the Attachment to this report.
This inspection constituted four post-maintenance testing samples as defined in IP 71111.19-05.
b. Findings
No findings were identified.
1R20 Outage Activities
.1 Other Outage Activities
a. Inspection Scope
The inspectors evaluated outage activities for an unscheduled outage that began on November 7, 2012, and continued through December 31, 2012. The inspectors reviewed activities to ensure the licensee considered risk in developing, planning, and implementing the outage schedule.
The inspectors observed or reviewed the reactor shutdown and cooldown, outage equipment configuration and risk management, electrical lineups, selected clearances, control and monitoring of decay heat removal, control of containment activities, personnel fatigue management, startup and heatup activities, and identification and resolution of problems associated with the outage. The inspectors observed the activities involving the replacement of three control rod drive mechanisms and main generator repairs.
This inspection constituted one other outage sample as defined in IP 71111.20-05.
b. Findings
No findings were identified.
1R22 Surveillance Testing
.1 Surveillance Testing
a. Inspection Scope
The inspectors reviewed the test results for the following activities to determine whether risk-significant systems and equipment were capable of performing their intended safety function and to verify testing was conducted in accordance with applicable procedural and TS requirements:
- Procedure 24.321.07, Operability of 480V bus 72CF Automatic Throwover Scheme (routine);
- Procedure 43.401.207, Local Leakage Rate Testing for Control Rod Drive Hatch T2301-X006 (IST); and
- Procedure 23.425.01, Activities for closing drywell for forced outage (IST).
The inspectors observed in-plant activities and reviewed procedures and associated records to determine the following:
- did preconditioning occur;
- the effects of the testing were adequately addressed by control room personnel or engineers prior to the commencement of the testing;
- acceptance criteria were clearly stated, demonstrated operational readiness, and were consistent with the system design basis;
- plant equipment calibration was correct, accurate, and properly documented;
- as-left setpoints were within required ranges; and the calibration frequency was in accordance with TSs, the UFSAR, procedures, and applicable commitments;
- measuring and test equipment calibration was current;
- test equipment was used within the required range and accuracy; applicable prerequisites described in the test procedures were satisfied;
- test frequencies met TS requirements to demonstrate operability and reliability; tests were performed in accordance with the test procedures and other applicable procedures; jumpers and lifted leads were controlled and restored where used;
- test data and results were accurate, complete, within limits, and valid;
- test equipment was removed after testing;
- where applicable for inservice testing activities, testing was performed in accordance with the applicable version of Section XI, American Society of Mechanical Engineers code, and reference values were consistent with the system design basis;
- where applicable, test results not meeting acceptance criteria were addressed with an adequate operability evaluation or the system or component was declared inoperable;
- where applicable, actual conditions encountering high resistance electrical contacts were such that the intended safety function could still be accomplished;
- prior procedure changes had not provided an opportunity to identify problems encountered during the performance of the surveillance or calibration test;
- equipment was returned to a position or status required to support the performance of its safety functions; and
- all problems identified during the testing were appropriately documented and dispositioned in the corrective action program.
Documents reviewed are listed in the Attachment to this report.
This inspection constituted one routine surveillance testing sample, two inservice testing samples, and one reactor coolant system leak detection inspection sample, as defined in IP 71111.22, Sections -02 and -05.
b. Findings
No findings were identified.
1EP4 Emergency Action Level and Emergency Plan Changes
.1 Emergency Action Level and Emergency Plan Changes
a. Inspection Scope
The regional staff performed an in-office review of the latest revisions of the Emergency Plan and various Emergency Plan Implementing Procedures located under ADAMS Accession Number ML12045A430 as listed in the Attachment.
The licensee transmitted the Emergency Plan Implementing Procedures revisions to the NRC pursuant to the requirements of 10 CFR Part 50, Appendix E, Section V, Implementing Procedures. The NRC review was not documented in a safety evaluation report and did not constitute approval of licensee-generated changes; therefore, this revision is subject to future inspection. The specific documents reviewed during this inspection are listed in the Attachment.
This inspection constituted one emergency action level and emergency plan changes sample as defined in IP 71114.04.
b. Findings
No findings were identified.
1EP6 Drill Evaluation
.1 Emergency Preparedness Drill Observation
a. Inspection Scope
The inspectors evaluated the conduct of a routine licensee emergency drill on October 16, 2012, to identify any weaknesses and deficiencies in classification, notification, and protective action recommendation development activities. The inspectors observed emergency response operations in the Emergency Offsite Facility and Technical Support Center to determine whether the event classification, notifications, and protective action recommendations were performed in accordance with procedures. The inspectors also attended the licensee drill critique to compare any inspector-observed weakness with those identified by the licensee staff in order to evaluate the critique and to verify whether the licensee staff was properly identifying weaknesses and entering them into the corrective action program. As part of the inspection, the inspectors reviewed the drill package and other documents listed in the to this report.
This emergency preparedness drill inspection constituted one sample as defined in IP 71114.06-05.
b. Findings
No findings were identified.
OTHER ACTIVITIES
Cornerstones: Initiating Events, Mitigating Systems, Barrier Integrity, Emergency Preparedness, Occupational Radiation Safety, Public Radiation Safety, and Security
4OA1 Performance Indicator Verification
.1 Mitigating Systems Performance Index - Residual Heat Removal System (MS-09)
a. Inspection Scope
The inspectors sampled licensee submittals for the Mitigating Systems Performance Index (MSPI) - Residual Heat Removal System performance indicator for the period from the third quarter 2011 through the third quarter 2012. To determine the accuracy of the performance index data reported during those periods, performance index definitions and guidance contained in the Nuclear Energy Institute (NEI) Document 99-02, Regulatory Assessment Performance Indicator Guideline, Revision 6, dated October 2009, was used. The inspectors reviewed the licensees operator narrative logs, issue reports, MSPI derivation reports, event reports, and NRC integrated inspection reports for the period of third quarter 2011 through the third quarter 2012 to validate the accuracy of the submittals. The inspectors reviewed the MSPI component risk coefficient to determine if it had changed by more than 25 percent in value since the previous inspection, and if so, that the change was in accordance with applicable NEI guidance. The inspectors also reviewed the licensees issue report database to determine if any problems had been identified with the performance index data collected or transmitted for this indicator and none were identified. Documents reviewed are listed in the Attachment to this report.
This inspection constituted one MSPI residual heat removal system sample as defined in IP 71151-05.
b. Findings
No findings were identified.
.2 Mitigating Systems Performance Index - Cooling Water Systems (MS-10)
a. Inspection Scope
The inspectors sampled licensee submittals for the MSPI - Cooling Water Systems performance indicator for the period from the third quarter 2011 through the third quarter 2012. To determine the accuracy of the performance index data reported during those periods, performance index definitions and guidance contained in the NEI Document 99-02, Regulatory Assessment Performance Indicator Guideline, Revision 6, dated October 2009, was used. The inspectors reviewed the licensees operator narrative logs, issue reports, MSPI derivation reports, event reports and NRC integrated inspection reports for the period of October 2011 through September 2012 to validate the accuracy of the submittals. The inspectors reviewed the MSPI component risk coefficient to determine if it had changed by more than 25 percent in value since the previous inspection, and if so, that the change was in accordance with applicable NEI guidance. The inspectors also reviewed the licensees issue report database to determine if any problems had been identified with the PI data collected or transmitted for this indicator and none were identified. Documents reviewed are listed in the to this report.
This inspection constituted one MSPI cooling water system sample as defined in IP 71151-05.
b. Findings
No findings were identified.
4OA2 Identification and Resolution of Problems
.1 Routine Review of Items Entered into the Corrective Action Program
a. Inspection Scope
As part of the various baseline inspection procedures discussed in previous sections of this report, the inspectors routinely reviewed issues during baseline inspection activities and plant status reviews to verify they were being entered into the licensees corrective action program at an appropriate threshold, adequate attention was being given to timely corrective actions, and adverse trends were identified and addressed. Attributes reviewed included: identification of the problem was complete and accurate; timeliness was commensurate with the safety significance; evaluation and disposition of performance issues, generic implications, common causes, contributing factors, root causes, extent-of-condition reviews, and previous occurrences reviews were proper and adequate; and the classification, prioritization, focus, and timeliness of corrective actions were commensurate with safety and sufficient to prevent recurrence of the issue. Minor issues entered into the licensees corrective action program as a result of the inspectors observations are included in the Attachment to this report.
These routine reviews for the identification and resolution of problems did not constitute any additional inspection samples. Instead, by procedure they were considered an integral part of the inspections performed during the quarter and documented in Section 1 of this report.
b. Findings
No findings were identified.
.2 Daily Corrective Action Program Reviews
a. Inspection Scope
In order to assist with the identification of repetitive equipment failures and specific human performance issues for follow-up, the inspectors performed a daily screening of items entered into the licensees corrective action program. This review was accomplished through inspection of the stations daily condition report packages.
These daily reviews were performed by procedure as part of the inspectors daily plant status monitoring activities and, as such, did not constitute any separate inspection samples.
b. Findings
No findings were identified.
.3 Semi-Annual Trend Review
a. Inspection Scope
The inspectors performed a review of the licensees corrective action program and associated documents to identify trends that could indicate the existence of a more significant safety issue. The inspectors review was focused on licensee human performance issues, but also considered the results of daily inspector corrective action program item screening discussed in Section 4OA2.2 above, and licensee trending reports. The inspectors review nominally considered the 6-month period of July 2012 through December 2012, although some examples expanded beyond those dates where the scope of the trend warranted.
The review also included issues documented outside the normal corrective action program including human performance steering committee and human performance department coordinator meetings, site/department/crew clock resets, human performance metrics, quality assurance audit/surveillance reports, self-assessment reports, interviews with management, and Maintenance Rule assessments. The inspectors compared and contrasted their results with the results contained in the licensees corrective action program trending reports. Corrective actions associated with a sample of the issues identified in the licensees trending reports were reviewed for adequacy.
The inspectors reviewed the 2012 performance improvement plans for several departments. The inspectors noted there have been several improvement plans during the past couple of years. The plans put forward during the current year are a culmination of lessons learned from the past programs and are more uniform among the various departments.
This review constituted one semi-annual trend inspection sample as defined in IP 71152-05.
b. Findings
No findings were identified.
.4 Annual Sample: Review of Operator Workarounds
a. Inspection Scope
The inspectors evaluated the licensees implementation of their process used to identify, document, track, and resolve operational challenges. Inspection activities included, but were not limited to, a review of the cumulative effects of the operator workarounds on system availability and the potential for improper operation of the system, potential impacts on multiple systems, and on the ability of operators to respond to plant transients or accidents.
The inspectors performed a review of the cumulative effects of operator workarounds.
The documents listed in the Attachment to this report were reviewed to accomplish the objectives of the inspection procedure. The inspectors reviewed both current and historical operational challenge records to determine whether the licensee was identifying operator challenges at an appropriate threshold, had entered them into their corrective action program and proposed or implemented appropriate and timely corrective actions which addressed each issue. Reviews were conducted to determine if any operator challenge could increase the possibility of an Initiating Event, if the challenge was contrary to training, required a change from long-standing operational practices, or created the potential for inappropriate compensatory actions. Additionally, all temporary modifications were reviewed to identify any potential effect on the functionality of Mitigating Systems, impaired access to equipment, or required equipment uses for which the equipment was not designed. Daily plant and equipment status logs, degraded instrument logs, and operator aids or tools being used to compensate for material deficiencies were also assessed to identify any potential sources of unidentified operator workarounds.
This review constituted one operator workaround annual inspection sample as defined in IP 71152-05.
b. Findings
No findings were identified.
.5 Selected Issue Follow-up Inspection: Operation with South Reactor Feed Pump Out of
Service
a. Inspection Scope
The inspectors selected a safety evaluation performed pursuant to 10 CFR 50.59 related to the operation at reduced power with the SRFP out of service to determine if the evaluation was adequate. The inspectors reviewed the safety evaluation and associated documents and discussed the timeframe for restoration of the SRFPT with licensee personnel. The feedwater system is currently in a degraded condition as a result of the SRFP being out of service. As such, the plant is limited to operation at reduced power due to the reduced feedwater flow.
The inspectors were concerned with the licensees long-term operation at or near 68 percent power. Specifically, the inspectors questioned the licensing basis for long-term operation with a single reactor feed pump. Operation with a single reactor feed pump increases the possibility of a reactor scram and complications resulting from the scram. To address the inspectors concerns, the licensee stated in a letter to the Regional Administrator, U.S. Nuclear Regulatory Commission - Region III, dated November 16, 2012, they intended to restore the SRFP to service during the first quarter of 2013, but these plans are contingent upon the successful refurbishment and testing of the SRFPT. Nevertheless, the licensee stated the SRFP would be restored no later than prior to plant startup following RF-16, scheduled for the first quarter of 2014.
At that point the plant will be able to resume operation at 100 percent licensed power.
This review constituted one in-depth problem identification and resolution sample as defined in IP 71152-05.
b. Findings
No findings were identified.
4OA3 Follow-Up of Events and Notices of Enforcement Discretion
.1 (Closed) Licensee Event Report (LER) 05000341/2012-003: Reactor Scram Due to
Degrading Condenser Vacuum
a. Inspection Scope
The inspectors reviewed the plants response to a reactor scram occurring on June 25, 2012. After completing repairs to main unit transformer 2B, reactor power was raised to approximately 22 percent and the unit was synchronized to the power grid. Shortly after operations began to increase power, multiple vibration-related alarms were received for the SRFP, and the pump tripped. The SRFP had catastrophically failed and as a result, condenser vacuum was decreasing. Operations performed a manual scram by taking the mode selector switch to shutdown. All automatic actuations and isolations occurred as designed.
The unit remained shut down in forced outage 12-02 and plant configuration changes were installed to isolate the SRFP from plant systems. The unit was restarted on July 22, 2012, increased power to 2 percent, and returned to a shutdown condition to repair a valve motor. The unit subsequently restarted on July 27, 2012, and achieved 68 percent power on July 30, 2012, using the north reactor feed pump.
The inspectors reviewed the root cause investigation report for this event. Documents reviewed as part of this inspection are listed in the Attachment to this report. This LER is closed.
This event follow-up review constituted one sample as defined in IP 71153-05.
b. Findings
Introduction:
A self-revealed Green finding and associated NCV of TS 5.4.1.a was identified for the licensees failure to establish and implement procedures recommended by Regulatory Guide 1.33, Revision 2, Appendix A, February 1978. Specifically, the licensee failed to control the three factors identified by the root cause evaluation team within their RF-15 SRFPT overhaul maintenance instructions and post-maintenance testing instructions; and within the operating procedures for the reactor feed pumps during synchronizing the main generator to the electrical grid following recovery from repairs performed on main unit transformer 2B. The SRFP catastrophically failed and as a result, the reactor was shut down because of decreasing condenser vacuum.
Description:
On June 25, 2012, after completing repairs to main unit transformer 2B, reactor power was raised to approximately 22 percent and the unit was synchronized to the power grid, and power ascension proceeded. Shortly after operations began to increase power, multiple vibration-related alarms were received for the SRFP, and the pump tripped. The SRFP had catastrophically failed and as a result, condenser vacuum was decreasing. Operations performed a manual scram by taking the mode selector switch to shutdown. A root cause evaluation team was identified to investigate the causes for the failure of the SRFPT documented in CARD 12-25544. The root cause evaluation team identified the cause of the SRFPT failure as the presence of three factors in concert: 1) no turbine diaphragm alignment with tight clearances; 2) automatic admission of steam with challenging thermal properties; and 3) less-than-adequate post-maintenance testing. The SRFPT had been overhauled by a vendor during the spring RF-15, and reassembled with tighter-than-design clearances between the diaphragm seals and rotor shaft. No alignment of the diaphragm had been included as a requirement in the overhaul specifications or following review of as-left clearance measurements. This resulted in a hard mechanical rub, which remained undetected following the overhaul. Additionally, the post-maintenance testing specified following the rebuild and refurbishment during RF-15 was not adequate to identify and resolve rubs.
A series of operational experience exists at Fermi regarding the SRFPT experiencing high vibrations followed by manual tripping, or catastrophic failure. Many of these issues resulted from problems with getting out moisture in the steam lines or turbine casings, and not entering the turbine, i.e., high pressure steam or reheat steam drainage. This reflects some piping configuration differences between the two pumps regarding long horizontal runs for the reheat steam to the SRFPT. At certain times in the past, the SRFPT has had longer warm-up requirements than its sibling. However, at the time of the recent failure, there were no differences in the operational guidance regarding placing the north or south feed pump in service first. Thus, with a wealth of operational experience, there was no recognition in the operating procedures that the north reactor feed pump turbine (NRFPT) should be placed in service first preferentially.
For the RF-15 overhaul, the original equipment manufacturer (Delaval, now Siemans)was not able to provide a field representative to support the RF-15 overhaul schedule for the SRFP. The maintenance instructions did not provide acceptance criteria for the clearances between the turbine rotor and the diaphragm seals. These clearances were tighter than design, and they were tighter on one side of the rotor than the other, i.e.,
they were not concentric. These clearances were identified and discussed, but were accepted. Further, the additional problems caused by non-concentric tight clearances were not recognized, leading to a failure to identify the need to perform an alignment of the diaphragm seals. Additionally, the post-maintenance testing was not robust enough to identify the presence of hard rubs between the rotor and diaphragm seals following overhaul.
Analysis:
The inspectors determined the failure to control the presence of three factors in concert: 1) no turbine diaphragm alignment with tight clearances; 2) automatic admission of steam with challenging thermal properties; and 3) less than adequate post-maintenance testing, was a performance deficiency that required evaluation using the SDP. The inspectors determined this finding was more than minor because it was associated with the equipment performance attribute of the Initiating Events Cornerstone and impacted the cornerstone objective of limiting the likelihood of those events that upset plant stability. This finding was determined to be of very low safety significance because, following IMC 0609, Table 4a, Characterization Worksheet for Initiating Events, Mitigating Systems, and Barrier Integrity Cornerstones, concluded the finding did not require quantitative assessment. Therefore, the finding was determined to be of very low safety significance (Green).
This finding has a cross-cutting aspect in the area of Human Performance, Work Practices, supervisory and management oversight aspect because the licensee failed to appropriately oversee the overhaul of the SRFPT by a vendor, and the post-maintenance testing and operation of the SRFPT during and after RF-15 (H.4 (c)).
Enforcement:
Technical Specification 5.4.1.a requires written procedures be established, implemented, and maintained for the activities specified in Regulatory Guide 1.33, Revision 2, Appendix A. Regulatory Guide 1.33, Revision 2, Appendix A, Item 4.0, requires procedures for startup, shutdown, and operation of the feedwater system; and item 9 requires procedures for performing maintenance. Contrary to the above, the licensee first failed to provide adequate maintenance instruction guidance for acceptance of as-left clearances between the turbine rotor and diaphragm seals, including issues regarding concentricity and requirements to align the diaphragm seals.
Second, the licensee failed to provide adequate post-maintenance testing robust enough to identify the presence of hard rubs. Finally, the procedures did not provide sufficient guidance to the operators to manage the challenging thermal properties of the transition to reheat steam being automatically applied to the SRFPT as opposed to the historically more normal power ascension using the NRFPT, including response to SRFPT shaft vibration reading greater than
.4 mils. The licensee included this issue in their corrective
action program as CARD 12-25544. Because this violation was of very low safety significance and it was entered into the licensees corrective action program, this violation is being treated as an NCV, consistent with the Enforcement Policy.
Inadequate Implementation of Overhaul, Post-Maintenance Testing, and Operation of South Reactor Feed Pump Turbine (NCV 05000341/20120005-02).
.2 (Closed) Licensee Event Report (LER) 05000341/2012-004: Operation or Condition
Prohibited by Technical Specification 3.3.3.1 The inspectors reviewed the August 27, 2012, engineering review of Environmental Qualification & Surveillance due to cable connector assemblies connected to position indication limit switches for 3/4 inch valve B3100-F019, reactor recirculation sample inboard isolation valve, had exceeded the Environmentally Qualified life.
Environmentally Qualified subject matter experts could not assure the limit switch cable connector assemblies could have endured the design basis accident. The cable connector assemblies are to be replaced during the next refueling outage. The licensee identified there was a violation of procedural adherence during a change in the preventative maintenance program that caused the Environmentally Qualified issue. No new findings were identified in the inspectors review. This finding constitutes a violation of minor significance that is not subject to enforcement action in accordance with Section 2.3.2 of the NRCs Enforcement Policy. The licensee documented the problem in CARD 12-27089. This LER is closed.
This event follow-up review constituted one sample as defined in IP 71153-05.
.3 (Closed) Licensee Event Report (LER) 05000341/2012-005: Reactor Scram Due to
Loss of 120 kV Power The inspectors reviewed the plants response to an automatic reactor scram due to the loss of the division 1 120 kilovolt (kV) switchyard occurring on September 14, 2012, resulting in the loss of the feedwater and condensate system. All plant systems responded to the scram as designed. Offsite power was restored to the electrical buses that evening. The unexpected loss of the 120kV switchyard was due to animal intrusion (bird). No findings were identified following review of this licensee event report (LER).
Documents reviewed in this inspection are listed in the Attachment to this report. This LER is closed.
This event follow-up review constituted one sample as defined in IP 71153-05.
.4 Manual Reactor Scram due to Hydrogen Leakage into the Stator Water Cooling System
a. Inspection Scope
The inspectors reviewed the plants response to a manual scram occurring on November 7, 2012. The reactor mode switch was taken to shutdown and the main turbine generator was manually tripped in response to excessive hydrogen gas leakage into the stator water cooling system from the main turbine generator. The scram was uncomplicated. Two control rods did not respond as expected. One control rod stopped at position 02 and was manually inserted by the operator. The second stopped at position 02 and then fully inserted into the core within the next two minutes with no additional operator action. Other plant systems responded as designed. The leak in the stator water cooling system was located and repaired. Three control rod mechanisms were replaced. Documents reviewed in this inspection are listed in the Attachment to this report.
This event follow-up review constituted one sample as defined in IP 71153-05.
b. Findings
No findings were identified.
.5 Oil Spill from Oil/Water Separator
a. Inspection Scope
The inspectors reviewed the plants response to an oil spill that occurred on November 1, 2012. During fire water header flushing operations, an oil/water mix was observed coming up from the oil water separator and oil storage sumps. The oil/water mix became mixed with the flushing water and ran into the storm water drain.
Subsequently, an oil sheen was observed at storm water outfall 002, which discharges into the Fermi overflow canal and, subsequently, into Swan Creek. Flushing operations were stopped. An oil containment boom was deployed at outfall 002 to contain the release. On November 2, 2012, Marine Pollution Control flushed the storm water system drain with fire header water to remove residual water and performed additional remediation. Documents reviewed in this inspection are listed in the Attachment to this report.
This event follow-up review constituted one sample as defined in IP 71153-05.
b. Findings
No findings were identified.
4OA5 Other Activities
.1 (Closed) NRC Temporary Instruction 2515/177: Managing Gas Accumulation in
Emergency Core Cooling, Decay Heat Removal, and Containment Spray Systems (NRC Generic Letter 2008-01)
a. Inspection Scope
During an earlier inspection period, the inspectors verified the licensee implemented or was in the process of implementing the commitments, modifications, and programmatically controlled actions described in the licensees response to NRC Generic Letter (GL) 2008-01, Managing Gas Accumulation in Emergency Core Cooling, Decay Heat Removal, and Containment Spray Systems. This earlier activity was conducted in accordance with Temporary Instruction (TI) 2515/177 and was documented in NRC Inspection Report 05000341/2012003. The TI remained opened for Fermi Power Plant because, at the conclusion of that inspection period, questions remained unresolved regarding the licensees interactions with the BWR Owners Group to resolve an apparent design deficiency and to address the potential license concern related to the note in TS 3.5.1.
During this inspection period, the inspectors reengaged the licensee regarding the status of the owners groups analysis and the status of their corrective actions. Based on the results documented in NRC Inspection Report 05000341/2012003 and follow-up interviews with the licensee, inspectors have determined the continuing efforts to resolve the TS 3.5.1 emergency core cooling system operating issue in combination with the initiated compensatory actions, appropriately address the immediate concern; therefore, this TI is considered closed for Fermi Power Plant.
The documents reviewed are listed in the Attachment to this report.
b. Findings
One licensee identified violation is documented in Section 4OA7, addressing the lack of supporting analysis for low pressure coolant injection (LPCI) subsystem operability in mode 3, in accordance with TS 3.5.1 Note that allows the manual realignment of LPCI.
.2 (Closed) NRC Temporary Instruction (TI) 2515/187: Inspection of Near-Term Task
Force Recommendation 2.3 Flooding Walkdowns
a. Inspection Scope
Inspectors accompanied the licensee on a sampling basis during their flooding and seismic walkdowns to verify the licensees walkdown activities were conducted using the methodology endorsed by the NRC. These walkdowns are being performed at all sites in response to a letter from the NRC to licensees, entitled Request for Information Pursuant to Title 10 of the Code of Federal Regulations 50.54(f) Regarding Recommendations 2.1, 2.3, and 9.3, of the Near-Term Task Force Review of Insights from the Fukushima Dai-Ichi Accident, dated March 12, 2012 (ADAMS Accession No.
4 of the letter requested licensees to perform external flooding walkdowns using an NRC-endorsed walkdown methodology (ADAMS Accession No.
ML12056A050). Nuclear Energy Industry document 12-07 titled, Guidelines for Performing Verification Walkdowns of Plant Protection Features, (ADAMS Accession No. ML12173A215) provided the NRC-endorsed methodology for assessing external flood protection and mitigation capabilities to verify plant features, credited in the current licensing basis for protection and mitigation from external flood events, are available, functional, and properly maintained. As documented in NRC Inspection Report 05000341/2012004, the inspectors completed the specified actions required by TI 2512/188. No findings were identified during that inspection effort. This TI is being closed in this report.
b. Findings
No findings were identified.
.3 (Closed) NRC TI 2515/188: Inspection of Near-Term Task Force Recommendation 2.3
Seismic Walkdowns
a. Inspection Scope
Inspectors accompanied the licensee on a sampling basis during their flooding and seismic walkdowns to verify the licensees walkdown activities were conducted using the methodology endorsed by the NRC. These walkdowns are being performed at all sites in response to a letter from the NRC to licensees entitled, Request for Information Pursuant to Title 10 of the Code of Federal Regulations 50.54(f) Regarding Recommendations 2.1, 2.3, and 9.3, of the Near-Term Task Force Review of Insights from the Fukushima Dai-Ichi Accident, dated March 12, 2012 (ADAMS Accession No.
3 of the March 12, 2012, letter requested licensees to perform seismic walkdowns using an NRC-endorsed walkdown methodology. Electric Power Research Institute document 1025286 titled, Seismic Walkdown Guidance, (ADAMS Accession No. ML12188A031) provided the NRC-endorsed methodology for performing seismic walkdowns to verify plant features, credited in the current licensing basis for seismic events, are available, functional, and properly maintained. As documented in NRC Inspection Report 05000341/2012004, the inspectors completed the specified actions required by TI 2512/188. No findings were identified during that inspection effort. This TI is being closed in this report.
b. Findings
No findings were identified.
4OA6 Management Meetings
.1 Exit Meeting Summary
On January 8, 2013, the inspectors presented the inspection results to Mr. K. Scott, Plant Manager, and other members of the licensee staff. The licensee acknowledged the issues presented. The inspectors confirmed none of the potential report input discussed was considered proprietary.
.2 Interim Exit Meetings
Interim exits were conducted:
- December 6, 2012, the inspection results for the TI 2515/177 were discussed with Mr. M. Caragher.
- December 14, 2012, the licensed operator requalification training annual operating test results were discussed with the Licensed Operator Requalification Lead Instructor, Mr. R. Duke, via telephone.
The inspectors confirmed none of the potential report input discussed was considered proprietary. Proprietary material received during the inspection was returned to the licensee.
4OA7 Licensee-Identified Violations
.1 The following violations of very low significance (Green) were identified by the licensee
and are violations of NRC requirements which meet the criteria of the NRC Enforcement Policy for being dispositioned as NCVs.
Title 10 CFR 50.65, Maintenance Rule, section (a)(1) requires, in part, that holders of an operating license shall monitor the performance or condition of structures, systems, or components within the scope of the rule as defined by 10 CFR 50.65 (b), against licensee established goals, in a manner sufficient to provide reasonable assurance such structures, systems, or components are capable of fulfilling their intended functions.
Contrary to the above, the system engineer for system T2300 primary containment (torus-to-reactor vacuum breakers) failed to perform evaluations of various CARDs that documented as-found conditions outside the torus-to-reactor vacuum breaker acceptance criteria to determine whether maintenance rule functional failures had occurred. The maintenance rule expert panel had determined the T2300 system should be monitored as (a)(1) at the time. CARD 11-30255 was issued for this concern, and the functional failure evaluations were performed. This finding was determined to be of very low safety significance because all the screening questions in IMC 0609, Attachment 04, Table 4a, for the Mitigating Systems Cornerstone were answered no.
.2 A finding of very low safety significance (Green) and associated violation of 10 CFR,
Part 50, Appendix B, Criterion III, Design Control was identified by the licensee for the failure to ensure the ECCS mode of operation of RHR would be capable of performing its mitigating function in mode 3 following RHR realignment from its shutdown cooling mode of operation. Specifically, the operability requirements of RHR in mode 3, as defined by TS 3.5.1, were not translated into applicable procedures or specifications of the system in that neither the procedures nor the design prevented the condition that would lead to steam void formation during a loss of coolant accident that initiates at this mode resulting in steam binding of the systems pumps and/or an adverse water hammer. The performance deficiency was determined to be more than minor because it was associated with the Mitigating Systems Cornerstone attribute of equipment performance and affected the cornerstone objective of ensuring the capability of systems that respond to initiating events to prevent undesirable consequences. A Phase II SDP was conducted using IMC 0609, Appendix G. The finding screened as very low safety significance. The licensee entered this concern into its corrective action program as CARD 12-24503 and initiated a Condition Evaluation for TS 3.5.1 ECCS Operating may be non-conservative. In the interim, the licensee has implemented actions to declare the division of RHR inoperable when used in the shutdown cooling mode of operation in mode 3. The safety function is maintained by the other division of RHR. The licensee plans to evaluate the BWR Owners Group analysis of the postulated mode 3 loss of coolant accident scenario and implement permanent procedural, design, and/or licensing basis changes as necessary.
ATTACHMENT:
SUPPLEMENTAL INFORMATION
KEY POINTS OF CONTACT
Licensee
- K. Scott, Plant Manager
- T. Barrett, Initial Licensed Operator Training Lead Instructor
- S. Berry, Manager, Systems
- M. Caragher, Director, Nuclear Engineering
- J. Davis, Manager, Nuclear Training
- R. Duke, Licensed Operator Requalification Training Lead Instructor
- J. Ellis, Manager, Work Management
- J. Ford, Director, Organization Effectiveness
- R. Keck, Manager, Plant Support Engineering
- G. Piccard, Manager, Performance Engineering
- Z. Rad, Manager, Licensing
- G. Strobel, Manager, Operations
- J. Thorson, Manager, Performance Improvement
- C. Wolfe, Manager, Projects
Nuclear Regulatory Commission
Jamnes
- L. Cameron, Chief, Reactor Projects Branch 6
Attachment
LIST OF ITEMS
OPENED, CLOSED AND DISCUSSED
Opened and Closed
- 05000341/2012005-01 FIN Failure of E4150F002
- 05000341/2012005-02 NCV Inadequate Implementation of Overhaul Post-maintenance Testing and Operation of South Reactor Feed Pump Turbine
- 05000341/2012-004 LER Operation or Condition Prohibited by Technical Specification 3.3.3.1
- 05000341/2012-005 LER Reactor Scram Due to Loss of 120 kV Power
Closed
- 05000341/2012-003 LER Reactor Scram Due to Degrading Condenser Vacuum TI 2515/177 TI Managing Gas Accumulation in Emergency Core Cooling, Decay Heat Removal, and Containment Spray Systems (NRC Generic Letter 2008-01)
TI 2515/187 TI Inspection of Near-Term Task Force Recommendation 2.3 Flooding Walkdowns TI 2515/188 TI Inspection of Near-Term Task Force Recommendation 2.3 Seismic Walkdowns Attachment