IR 05000413/2014004
| ML14295A537 | |
| Person / Time | |
|---|---|
| Site: | Catawba  |
| Issue date: | 10/22/2014 |
| From: | Frank Ehrhardt NRC/RGN-II/DRP/RPB1 |
| To: | Henderson K Duke Energy Carolinas |
| References | |
| IR 2014004 | |
| Download: ML14295A537 (26) | |
Text
October 22, 2014
SUBJECT:
CATAWBA NUCLEAR STATION - NRC INTEGRATED INSPECTION REPORT 05000413/2014004, 05000414/2014004
Dear Mr. Henderson:
On September 30, 2014, the U.S. Nuclear Regulatory Commission (NRC) completed an inspection at your Catawba Nuclear Station Units 1 and 2. The enclosed inspection report documents the inspection results which were discussed on October 6, 2014, with you and other members of your staff.
NRC inspectors documented two findings of very low safety significance (Green) which involved violations of NRC requirements in this report. Further, a licensee-identified violation, which was determined to be of very low safety significance (Green), is listed in this report. The NRC is treating these violations as non-cited violations (NCVs) consistent with Section 2.3.2.a of the Enforcement Policy. If you contest the violations or the 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 20555-001; with copies to the Regional Administrator Region II; the Director, Office of Enforcement, U.S. Nuclear Regulatory Commission, Washington, DC 20555-0001; and the NRC Resident Inspector at Catawba. If you disagree with a cross-cutting aspect assignment 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 II, and the NRC Resident Inspector at Catawba. In accordance with Title 10 of the Code of Federal Regulations 2.390, Public Inspections, Exemptions, Requests for Withholding, 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 (PARS) component of NRCs Agencywide Documents Access and Management System (ADAMS). ADAMS is accessible from the NRC Web site at http://www.nrc.gov/reading-rm/adams.html (the Public Electronic Reading Room).
Sincerely,
/RA/
Frank Ehrhardt, Chief Reactor Projects Branch 1 Division of Reactor Projects
Docket Nos.: 50-413, 50-414 License Nos.: NPF-35, NPF-52
Enclosure:
Integrated Inspection Report 05000413/2014004, 05000414/2014004 w/Attachment: Supplemental Information
REGION II==
Docket Nos.:
50-413, 50-414
License Nos.:
Report Nos.:
05000413/2014004, 05000414/2014004
Licensee:
Duke Energy Carolinas, LLC
Facility:
Catawba Nuclear Station, Units 1 and 2
Location:
York, SC 29745
Dates:
July 1, 2014, through September 30, 2014
Inspectors:
A. Hutto, Senior Resident Inspector R. Cureton, Resident Inspector L. Pressley, Resident Inspector P. Capehart, Sr. Operations Engineer (Section 1R11)
A. Toth, Operations Engineer (Section 1R11)
Approved by:
Frank Ehrhardt, Chief
Reactor Projects Branch 1
Division of Reactor Projects
Enclosure
SUMMARY OF FINDINGS
IR 05000413/2014-004, 05000414/2014-004; 7/1/2014 - 9/30/2014; Catawba Nuclear Station,
Units 1 and 2; Fire Protection. Other
The report covered a three-month period of inspection by the resident inspectors and two Region-based reactor inspectors. Two Green non-cited violations (NCVs) were identified. The significance of inspection findings are indicated by their color (i.e., greater than Green, or Green, White, Yellow, Red) 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 12, 2012. The NRCs program for overseeing the safe operation of commercial nuclear power reactors is described in NUREG-1649, Reactor Oversight Process revision 5.
Cornerstone: Mitigating Systems
- Green: An NRC-identified non-cited violation (NCV) of the Unit 2 Facility Operating License, Condition 2.C.5, Fire Protection Program, was identified for failure to implement and maintain all provisions of the approved fire protection program. The inspectors identified a degraded committed fire barrier that was not evaluated as a fire impairment.
The inspectors determined the failure to perform the required fire impairment actions was a performance deficiency (PD). The PD was more than minor because it was associated with the Mitigating System Cornerstone attribute of Protection against External Factors (fire) and adversely affected the cornerstone objective in that there was no reasonable assurance the degraded fire barrier would fulfill its designed 3-hour fire rating. The inspectors determined the finding was determined to be of very low safety significance (Green) because a fully functioning automatic suppression system on either side of the barrier was in place. This finding had a cross-cutting aspect of identification (P.1), as described in the Problem Identification and Resolution cross-cutting area as the licensee failed to enter the damaged fire barrier into their corrective action program which prevented the appropriate fire protection program reviews and compensatory actions. (Section 1R05)
- Green: A NRC-identified non-cited violation (NCV) was identified for the licensees failure to adequately implement their administrative procedure for operability/functionality assessments as applied to the evaluation of Unit 1 diesel connecting rod bearing rotations.
The inspectors determined that the licensees failure to implement the requirements of NSD 203 was a performance deficiency (PD). The PD was more than minor because it was associated with the Mitigating Systems cornerstone attribute of Equipment Performance and adversely affected the cornerstone objective to ensure availability of systems that respond to initiating events in that stagnant DG lube oil temperature could have decreased below the operability limit that was subsequently established by the licensee. The finding was determined to be of very low safety significance (Green) in that it does not represent an actual loss of safety function of a single train for greater than its TS allowed outage time.
This finding had a cross-cutting aspect of evaluation (P.2), as described in the Problem Identification and Resolution cross-cutting area as the licensee failed to adequately evaluate the DG lube oil standby temperature during investigation of DG connecting rod bearing rotations. (Section 4OA5)
One violation of very low safety significance (Green), which was identified by the licensee, has been reviewed by the inspectors. Corrective actions taken or planned by the licensee have been entered into the licensees corrective action program. This violation and corrective action tracking number are listed in section 4OA7.
REPORT DETAILS
Summary of Plant Status
Unit 1 operated at or near 100 percent Rated Thermal Power (RTP) for the entire inspection period.
Unit 2 operated at or near 100 percent RTP until July 24, 2014, when power was reduced to approximately 45 percent RTP to support activities to locate and repair a main condenser tube leak. Unit 2 was returned to 100 percent RTP on July 28, 2014, and operated at or near 100 percent RTP for the remainder of the inspection period.
REACTOR SAFETY
Cornerstones: Initiating Events, Mitigating Systems, Barrier Integrity
==1R01 Adverse Weather Protection
a. Inspection Scope
Adverse Weather Conditions:==
The inspectors walked down selected committed yard drain catch basins immediately following a period of heavy rain to verify that the drains were functioning properly with no blockages restricting flow. The inspectors also verified that the drains were clear of external obstructions that could affect performance.
b. Findings
No findings were identified.
==1R04 Equipment Alignment
a. Inspection Scope
Partial Walkdowns:==
The inspectors performed four partial system walkdowns during the activities listed below to assess the operability of redundant or diverse trains and components when safety-related equipment was inoperable. The inspectors performed walkdowns to identify any discrepancies that could impact the function of the system and, therefore, potentially increased risk. The inspectors reviewed applicable operating procedures and walked down system components, selected breakers, valves, and support equipment to determine if they were in the correct position to support system operation. The inspectors reviewed protected equipment sheets, maintenance plans, and system drawings to determine if 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.
Documents reviewed are listed in the Attachment.
- Unit 2 B train of component cooling water (KC) system due to the 2A1 KC pump out of service for planned maintenance
- Unit 1 A train of Safety Injection system due to the 1B train out of service for planned maintenance
- Unit 1 auxiliary feedwater pumps with the standby shutdown facility out of service for planned maintenance
- Unit 1 A train of control room area ventilation system with Unit 2 B train out of service for planned maintenance
b. Findings
No findings were identified.
==1R05 Fire Protection
a. Inspection Scope
Fire Protection Walkdowns:==
The inspectors walked down accessible portions of the five plant areas listed below to assess the licensees control of transient combustible material and ignition sources, fire detection and suppression capabilities, fire barriers, and any related compensatory measures. The inspectors observed the fire protection suppression and detection equipment to determine whether any conditions or deficiencies existed which could impair the operability of that equipment. The inspectors selected the areas based on a review of the licensees safe shutdown analysis probabilistic risk assessment and sensitivity studies for fire-related core damage accident sequences. Documents reviewed are listed in the Attachment.
- Unit 1 auxiliary feedwater pump room
- Unit 2 auxiliary feedwater pump room
- Service Building elevation 568
- Fire Area 8, Unit 1 Essential Switchgear Room
- Fire Area 25, Diesel Generator Building, Room 1A
b. Findings
Introduction:
An NRC-identified Green non-cited violation (NCV) of the Unit 2 Facility Operating License, Condition 2.C.5, Fire Protection Program, was identified for failure to implement and maintain all provisions of the approved fire protection program. The inspectors identified a degraded committed fire barrier that was not evaluated as a fire impairment.
Description:
During a fire protection walkdown of the Unit 2 auxiliary feedwater (CA)pump room, the inspectors identified a damaged and degraded access hatch to the turbine driven CA pump room which also served as a committed three hour fire barrier.
The left hatch cover hinge was damaged causing a one inch gap along the left side of the hatch and exposing the internal insulation. A work request had been initiated to repair the hinge; however, the discrepancy was not entered into the licensees corrective action program. Consequently, fire impairment actions were not performed as required by procedure Nuclear System Directive (NSD)-316, Fire Impairment and Surveillance.
The inspectors informed the licensee of the condition and a continuous fire watch was established until the hatch was repaired.
Analysis:
The inspectors determined the failure to perform the required fire impairment actions for the damaged turbine driven CA pump room fire barrier was a performance deficiency (PD). The PD was more than minor because it was associated with the Mitigating System Cornerstone attribute of Protection against External Factors (fire) and adversely affected the cornerstone objective in that there was no reasonable assurance the degraded fire barrier (access hatch) would fulfill its designed 3-hour fire rating.
Using IMC 0609, Significance Determination Process, Attachment 0609.04, Phase 1 Initial Screening and Characterization of Findings, Table 3b, the inspectors determined the finding degraded the fire protection defense-in-depth strategies. The inspectors reviewed IMC 0609, Appendix F, and determined that the finding impacted the Fire Confinement Finding Category. Based on review of IMC 0609, Appendix F, qualitative screening question Task 1.4.3-C, the finding was determined to be of very low safety significance (Green) because a fully functioning automatic suppression system on either side of the barrier was in place. This finding had a cross-cutting aspect of identification (P.1), as described in the Problem Identification and Resolution cross-cutting area as the licensee failed to enter the damaged fire barrier into their corrective action program which prevented the appropriate fire protection program reviews and compensatory actions.
Enforcement:
Catawba Unit 1 and 2 Facility Operating Licenses, Condition 2.C.5, required that the licensee shall implement and maintain in effect all provisions of the approved fire protection program as described in Section 9.5.1 of the Updated Final Safety Analysis Report (UFSAR). Catawba UFSAR section 9.5.1.2 stated in part that administrative controls are included in NSDs to manage impairments to fire protection features in that NSD-316, Section 316.6 required in part, that an impaired fire protection feature shall be immediately reported and entered into the impairment entry log, and that the fire protection engineer shall be contacted for establishment of appropriate compensatory measures. Contrary to the above, on August 19, 2014, the licensee failed to implement and maintain in effect all provisions of the approved fire protection program as described in Section 9.5.1 of the UFSAR in that fire impairment actions were not performed as required by the procedure NSD-316, Section 316.6. Since the finding was of very low safety significance and has been entered into the licensees corrective action program as PIP C-14-8529, this violation was treated as an NCV, consistent with the NRC Enforcement Policy, and is identified as NCV 05000414/2014004-01, Failure to Implement Fire Impairment Requirements for a Degraded Committed Fire Barrier.
==1R06 Flood Protection Measures
a. Inspection Scope
Underground Cables:==
The inspectors entered two conduit manholes (RN conduit) CMH-10A and CMH-2 to verify that the cables were not submerged, that the cables were not damaged or degraded, and that the sump pumps were functioning properly. Documents reviewed are listed in the Attachment.
b. Findings
No findings were identified.
==1R11 Licensed Operator Requalification (LOR) Program and Licensed Operator Performance
a.
==
Inspection Scope
Quarterly Resident Inspector LOR Activity Review: The inspectors observed Simulator Exercise Guide (SEG) S-30 on July 16, 2014, and Annual Simulator Exam ASE-2 on July 31, 2014, to assess the performance of licensed operators during a license operator requalification. The inspectors assessed overall crew performance, clarity and formality of communications, use of procedures, alarm response, control board manipulations, group dynamics and supervisory oversight. The inspectors observed the post-exercise critiques to determine whether the licensee identified deficiencies and discrepancies that occurred during the simulator training and exam.
SEG S-30 included a loss of operator aid computer, followed by a degraded grid condition, rapid down power and load rejection to separate from the grid. The exercise concluded with a turbine trip/reactor trip resulting in a loss power to the emergency busses and a natural circulation cool down of the reactor coolant system. ASE-2 included an atmospheric steam dump failure, a runback due to the loss of a generator stator cooling pump and a small break Loss of Coolant Accident (LOCA) which increased to a large break LOCA. Documents reviewed are listed in the Attachment.
Quarterly Resident Inspector Licensed Operator Performance Review: The inspectors observed operators in the main control room and assessed their performance during a Unit 2 power reduction to less than 50 percent RTP to allow main condenser tube leak inspection and repair. The inspectors also observed portions of the Unit 2 power increase to 100 percent RTP following the condenser repairs. Documents reviewed are listed in the Attachment.
Biennial Requalification Program Review: The inspectors reviewed documentation, interviewed licensee personnel, and observed the administration of operating tests associated with the licensees operator requalification program to assess the effectiveness of the facility licensee in implementing requalification requirements identified in 10 CFR Part 55, Operators Licenses. The evaluations were also performed to determine if the licensee effectively implemented operator requalification guidelines established in NUREG-1021, Operator Licensing Examination Standards for Power Reactors, and Inspection Procedure 71111.11, Licensed Operator Requalification Program. The inspectors also evaluated the licensees simulation facility for adequacy for use in operator licensing examinations using ANSI/ANS-3.5-2009, American National Standard for Nuclear Power Plant Simulators for use in Operator Training and Examination. The inspectors observed three crews during the performance of the operating tests. Documentation reviewed included written examinations, Job Performance Measures (JPMs), simulator scenarios, licensee procedures, on-shift records, simulator modification request records, simulator performance test records, operator feedback records, licensed operator qualification records, remediation plans, watchstanding records, and medical records. The records were inspected using the criteria listed in Inspection Procedure 71111.11. Documents reviewed are listed in the Attachment.
b. Findings
No findings were identified.
==1R12 Maintenance Effectiveness
a. Inspection Scope
==
The inspectors reviewed the two activities listed below for items such as: 1) appropriate work practices; 2) identifying and addressing common cause failures; 3) scoping in accordance with 10 CFR 50.65(b) of the Maintenance Rule; 4) characterizing reliability issues for performance; 5) trending key parameters for condition monitoring; 6) charging unavailability for performance; 7) classification and reclassification in accordance with 10 CFR 50.65(a)(1) or (a)(2); and 8) appropriateness of performance criteria for structures, systems, and components (SSCs)/functions classified as (a)(2) and/or appropriateness and adequacy of goals and corrective actions for SSCs/functions classified as (a)(1).
For each item selected, the inspectors performed a detailed review of the problem history and surrounding circumstances, evaluated the extent of condition reviews as required, and reviewed the generic implications of the equipment and/or work practice problem. Documents reviewed are listed in the Attachment.
- PIP C-14-6143, Main generator hydrogen seal oil mulsifyre valve 1RF-91 suffered catastrophic failure during testing
- PIP C-14-5614, Unit 1 containment penetration super system declared maintenance rule a(1)
b. Findings
No findings were identified.
==1R13 Maintenance Risk Assessments and Emergent Work Control
a. Inspection Scope
==
The inspectors reviewed the following five activities to determine if the appropriate risk assessments were performed prior to removing equipment for work. When emergent work was performed, the inspectors reviewed the risk assessment to determine that the plant risk was promptly reassessed and managed. The inspectors reviewed the use of the licensees risk assessment tool and risk categories in accordance with Nuclear System Directive (NSD) 415, Operational Risk Management (Modes 1-3), to verify there was appropriate guidance to comply with 10 CFR 50.65(a)(4). Documents reviewed are listed in the Attachment.
- Equipment protection plan for the 2B2 component cooling water pump out of service for maintenance (yellow risk condition)
- Critical Activity Plan for service water return piping excavation and inspections
- Equipment protection plan for the 2B auxiliary feedwater pump out of service for maintenance (yellow risk condition)
- Unit 1 equipment protection plan and risk assessment for diesel generator 1B out of service maintenance and inspections (yellow risk condition)
- Unit 2 equipment protection plan and risk assessment for diesel generator 2A out of service maintenance and inspections (yellow risk condition)
b. Findings
No findings were identified.
==1R15 Operability Determinations and Functionality Assessments
a. Inspection Scope
==
The inspectors evaluated the technical adequacy of the five operability evaluations or functionality assessments listed below to determine if Technical Specification (TS)operability was properly justified and the subject components and systems remained available such that no unrecognized increase in risk occurred. The inspectors reviewed the operability determinations to verify that they were made as specified by NSD 203, Operability. The inspectors reviewed the Updated Final Safety Analysis Report (UFSAR) to determine that the systems and components remained available to perform their intended function. Documents reviewed are listed in the Attachment.
- PIP C-14-5788, Non-conservatism identified with cooling time requirements for fuel assemblies with non-fuel hardware
- PIP C-14-05363, Operability of the 1A Emergency Diesel Generator (EDG) with two cam door bridge plate screws not installed
- PIP C-14-7832, Two cap screws missing from the 2B CA pump motor terminal box
- PIP C-14-7638, Fueling Water Storage Tank (FWST) Trench - Unit 2 trench area between the FWST and Aux Building has deteriorating conditions
b. Findings
No findings were identified.
==1R18 Plant Modifications
a. Inspection Scope
==
The inspectors reviewed the following two plant modifications to verify the adequacy of the modification package, and to evaluate the modification for adverse effects on system availability, reliability and functional capability. Documents reviewed are listed in the Attachment.
Permanent
- EC 110640, Install new FLEX connection on A train nuclear service water (RN)
Supply Header
Temporary
b. Findings
No findings were identified.
==1R19 Post Maintenance Testing
a. Inspection Scope
==
The inspectors reviewed the seven post-maintenance tests listed below to determine if procedures and test activities ensured system operability and functional capability. The inspectors reviewed the licensees test procedures to determine if the procedures adequately tested the safety function(s) that may have been affected by the maintenance activities, that the acceptance criteria in the procedures were consistent with information in the applicable licensing basis and/or design basis documents, and that the procedures had been properly reviewed and approved. The inspectors also witnessed the tests and/or reviewed the test data to determine if test results adequately demonstrated restoration of the affected safety function(s). Documents reviewed are listed in the Attachment.
- Safety Injection Pump 1B performance test following preventive maintenance (PM)
- Functional testing of 2B charging pump following motor PMs
- 1N-41 power range nuclear instrument functional testing following power supply replacement
- Standby Shutdown Facility Diesel Isochronous Test following diesel PMs
- Unit 2, B train control room area outside air pressure filter trains performance test following maintenance
- 2A Diesel Generator performance test following mid-cycle maintenance
b. Findings
No findings were identified.
==1R22 Surveillance Testing
a. Inspection Scope
==
For the five tests listed below, the inspectors witnessed testing and/or reviewed the test data to determine if the SSCs involved in these tests satisfied the requirements described in the Technical Specifications, the UFSAR, and applicable licensee procedures, and that the tests demonstrated that the SSCs were capable of performing their intended safety functions.
Surveillance Tests
- PT/1/A/4200/009 A, Auxiliary Safeguards Test Cabinet Periodic Test
- PT/2/A/4350/002 A, Diesel Generator 2A Operability Test
- PT/2/A/4450/005 B, Containment Air Return Fan 2B and Hydrogen Skimmer Fan 2B Performance Test
In-Service Tests
- PT/0/A/4400/022 B, Nuclear Service Water Pump Train B Performance Test (2B)
RCS Leakage
- PT/2/A/4150/001 D, Reactor Coolant System Leakage Calculation
b. Findings
No findings were identified.
Cornerstone: Emergency Preparedness
1EP6 Drill Evaluation
a. Inspection Scope
The inspectors observed and evaluated the licensees emergency planning performance during two drills conducted on July 24, 2014, and September 4, 2014. The inspectors reviewed licensee activities that occurred in the simulator and the Technical Support Center during the simulated events. The inspectors assessment focused on the timeliness and accuracy of the event classification, notification of offsite agencies, and the overall response of the personnel involved in the drills from an operations and emergency planning perspective. The performance of the Emergency Response Organization was evaluated against applicable licensee procedures and regulatory requirements. The inspectors attended the post-exercise critique for the drills to evaluate the licensee's self-assessment process for identifying potential deficiencies relating to failures in classification and notification. The inspectors reviewed the completed licensee critiques documenting the overall performance of the Emergency Response Organization.
b. Findings
No findings were identified.
OTHER ACTIVITIES
4OA1 Performance Indicator (PI) Verification
a. Inspection Scope
The inspectors sampled licensee data to confirm the accuracy of reported PI data for the four indicators during periods listed below. To determine the accuracy of the reported PI elements, the reviewed data was assessed against PI definitions and guidance contained in Nuclear Energy Institute 99-02, Regulatory Assessment Indicator Guideline, Rev. 6. Documents reviewed are listed in the Attachment.
Cornerstone: Initiating Events
- Unplanned Transients, Unit 1 & 2
Cornerstone: Mitigating Systems
- MSPI - Residual Heat Removal, Unit 1 & 2
The inspectors reviewed the licensees procedures and methods for compiling and reporting the PIs including the Reactor Oversight Program Mitigating Systems Performance Indicator Basis Document for Catawba. The inspectors reviewed the raw data for the PIs listed above for the period of July 1, 2013, through June 30, 2014. The inspectors also independently screened TS Action Item Logs, selected control room logs, work orders and surveillance procedures, and maintenance rule failure determinations to determine if unavailability/unreliability hours were properly reported.
The inspectors compared the licensees raw data against the graphical representations and specific values contained on the NRCs public web page for 2013-2014. The inspectors also reviewed the past history of PIPs for systems affecting the Mitigating Systems Performance Indicators listed above for any that might have affected the reported values. Documents reviewed are listed in the Attachment.
b. Findings
No findings were identified.
4OA2 Problem Identification and Resolution
.1 Daily Review
As required by Inspection Procedure 71152, Problem Identification and Resolution, and in order to help identify repetitive equipment failures or specific human performance issues for follow-up, the inspectors performed screening of items entered into the licensees corrective action program. This was accomplished by reviewing copies of PIPs, attending selected daily Site Direction and PIP screening meetings, and accessing the licensees computerized database.
.2 Annual Follow-up of Selected Issues
a. Inspection Scope
Operator Workarounds: The inspectors reviewed the cumulative effects of deficiencies that constituted operator workarounds to determine if they could affect: the reliability, availability, and potential for misoperation of a mitigating system; multiple mitigating systems; or the ability of operators to respond in a correct and timely manner to plant transients and accidents. The inspectors also assessed if operator workarounds were being identified and entered into the licensees corrective action program at an appropriate threshold. Documents reviewed are listed in the Attachment.
b. Findings
No findings were identified.
4OA3 Follow-up of Events and Notices of Enforcement Discretion (NOED)
(Closed) Unresolved Item (URI)0500413/2014002-01, NOED 14-2-001 to Allow Bearing Replacement and Testing of the 1A Diesel Generator
(Closed) Unresolved Item (URI)0500413/2014009-01, Review of Root Cause Analysis for the #7 Bearing Rotation and Effectiveness of Previous Corrective Actions
(Closed) Licensee Event Report (LER) 05000413/2014-001-00, Condition Prohibited by Technical Specifications (TS) and Notice of Enforcement Discretion Due to Misaligned Connecting Rod Bearing on Diesel Generator 1A
On March 4, 2014, the 1A diesel generator (DG) was declared inoperable for planned maintenance activities. Part of this maintenance activity involved taking position measurements of the piston connecting rod bearings. These position measurements were implemented by the licensee following a 2006 bearing rotation and were taken once every 18 months for each DG. The licensee discovered that the bearing for connecting rod number 7 had rotated approximately 25 degrees from its normal horizontal position. Based on this observation, the licensee decided to replace the bearing to allow for an analysis of the cause of the rotation. After inspection of the removed bearing it was determined that the amount of movement did not challenge the ability of the bearing to perform its function.
On March 6, 2014, the licensee requested enforcement discretion for an additional 60 hours6.944444e-4 days <br />0.0167 hours <br />9.920635e-5 weeks <br />2.283e-5 months <br /> allowed outage time for the 1A DG in order to complete connecting rod number 7 bearing replacement and testing and preclude a plant shutdown of Unit 1. The NRC verbally granted NOED 14-2-001 at 8:00 p.m. on March 6, 2014. The licensee subsequently returned the 1A DG and support systems to an operable status on March 9 at 3:40 a.m., which was within the completion time approved in the NOED.
On March 10, 2014, the licensee found that the number 1 bearing on the 1B DG had rotated approximately 11/16 of an inch during planned maintenance. This prompted the NRC to initiate a special inspection team to investigate the bearing issues. The special inspection team opened a URI to review the root cause analysis and to assess the effectiveness of corrective actions following a previous bearing rotation that was investigated in 2006. Subsequently on May 14, 2014, the 1A DG number 6 bearing was found rotated during outage maintenance.
In NRC Integrated Inspection Report 05000413, 414/2014002, the inspectors identified a URI for the issuance of NOED 14-2-001. Additionally, in NRC Special Inspection Report 05000413/2014009, the inspectors identified a URI to review the root cause and previous corrective actions related to the bearing rotation event that led to the NOED request. The inspectors reviewed the associated LER, root cause evaluation, and corrective actions to determine if any performance deficiencies contributed to the need for the NOED and whether previous corrective actions for a prior bearing rotation in 2006 were effective.
The inspectors found the licensees root cause analysis was sufficiently detailed and used a number of evaluation techniques including barrier analysis, event and causal factor charting, failure mode and effects analysis, and organizational and programmatic to analyze the event. The root cause team was unable to identify a root cause for the event; however, a most probable cause and a contributing cause were identified. The most probable cause was identified as an interaction of factors, which by themselves were considered unlikely to cause the observed bearing rotations, but in combination created a condition where rotation could occur. The most significant of these factors were lower yield strength and elastic limits in replacement bearings, low standby lube oil temperatures in the stagnant portion of the lube oil system, and an oversized bore in the 1A number 6 connecting rod. The contributing cause identified was an insufficient evaluation of the potential contributors to the 1A DG number 6 connecting rod bearing rotation in 2006.
The licensee implemented a number of corrective actions on the Unit 1 DGs to address the factors identified above that reduce the margin to bearing rotation conditions. The 1A DG number 6 connecting rod was replaced, the lube oil systems on both Unit 1 DGs were modified to allow warm up of the entire lube oil system prior to planned engine starts, and high point vents were installed. Four additional bearings on the 1A DG and three additional bearings on the 1B DG were replaced due to similar operating history and manufacturer of the bearings that were found to be rotated. Lube oil was changed to a straight 40 weight as recommended by the manufacturer to reduce viscosity at lower starting temperatures. Additional corrective actions planned to prevent recurrence include the procurement of bearings with improved mechanical properties to replace the existing non-Enterprise bearings, and the implementation of a modification to the lube oil keep warm systems to heat the entire volume of the lube oil during standby conditions.
The inspectors determined that a licensee-identified violation of 10 CFR Criterion XVI for inadequate corrective actions to prevent recurrence following a 2006 bearing rotation occurred. The enforcement aspects of this violation are discussed in section 4OA7 of this report. Documents reviewed are listed in the Attachment.
4OA5 Other Activities
.1 Independent Spent Fuel Storage Installation Radiological Controls
a. Inspection Scope
The inspectors reviewed the licensees procedures and observed operations associated with storing spent fuel in the Independent Spend Fuel Storage Installation in accordance with Inspection Procedure 60855.1. The inspectors observed selected licensee activities related to the loading of casks number 76 and 77, to verify that they performed these activities in a safe manner and in compliance with approved procedures. Documents reviewed are listed in the Attachment.
b. Findings
No findings of significance were identified.
.2 (Closed) Unresolved Item (URI)0500413/2014009-02, Review of Completed Prompt
Determination of Operability (PDO) and Compensatory Actions
a. Inspection Scope
In NRC Special Inspection Report 05000413/2014002, the inspectors identified a URI to review the PDO and any completed compensatory actions related to the Unit 1 diesel generator standby lube oil temperature impact on connecting rod bearing rotation.
b. Findings
Introduction:
A Green NRC-identified non-cited violation (NCV) was identified for the licensees failure to adequately implement their administrative procedure for operability/functionality assessments as applied to the evaluation of Unit 1 diesel connecting rod bearing rotations.
Description:
On March 4, 2014, the 1A DG number 7 connecting rod bearing was found rotated during a routine inspection. Subsequently, on March 10, 2014, the 1B DG number 1 connecting rod bearing was also found rotated. The licensee had performed an immediate determination of operability (IDO) but the inspectors noted that a PDO to address standby lube oil temperatures had not been performed. The IDO, documented in PIP C-14-2590, concluded in part that the cause of the bearing rotation was attributed to cold lube oil transients during diesel starts following outage maintenance periods; however, this conclusion had not been validated. Licensee procedure NSD-203, Operability/Functionality, Section 203.7.2.1, Circumstances Requiring a PDO, stated that a PDO was required when the IDO relies on assumptions that have not been justified and additional information could negate a previous determination that there is a reasonable expectation of operability.
In response to the inspectors concerns, the licensee performed a PDO that evaluated DG 1B and 2B lube oil temperature data from installed temperature instruments in the lube oil system at the inlet to the engine. The licensee concluded that even during ambient conditions as low as 79F, lube oil entering the engine remains well above 90F (the vendor specified limit) and the DGs were fully operable with no compensatory actions required. However, the inspectors identified that the evaluation failed to account for instrument response time nor did it include data from the 1A DG which historically had lower standby lube oil temperatures. As part of the root cause investigation for the connecting rod bearing rotations, further analysis of lube oil temperature effects on bearing performance showed that during routine starts of the DGs, an in surge of lube oil from the stagnant portion of the system would enter the engine at essentially ambient room temperature. As a result, the licensee implemented an operability limit of 90F during standby conditions on the coldest portion of the lube oil system.
Analysis:
The inspectors determined that the licensees failure to implement the requirements of NSD 203 was a performance deficiency (PD). The PD was more than minor because it was associated with the Mitigating Systems cornerstone attribute of Equipment Performance and adversely affected the cornerstone objective to ensure availability of systems that respond to initiating events, in that if left uncorrected the stagnant DG lube oil temperature could have decreased below the operability limit that was subsequently established by the licensee. The finding was determined to be of very low safety significance (Green), based on the Phase 1 screening criteria in Manual Chapter 0609, Attachment 4, Table 4a, in that it does not represent an actual loss of safety function of a single train for greater than its TS allowed outage time. This finding had a cross-cutting aspect of evaluation (P.2), as described in the Problem Identification and Resolution cross-cutting area as the licensee failed to adequately evaluate the DG lube oil standby temperature during investigation of DG connecting rod bearing rotations.
Enforcement:
10 CFR 50, Appendix B, Criterion V, Instructions, Procedures, and Drawings, required, in part, that activities affecting quality shall be prescribed by procedures of a type appropriate to the circumstances and shall be accomplished in accordance with these procedures. NSD-203, Operability/Functionality implements the licensees requirements for operability determinations for safety related equipment covered by technical specifications. NSD-203, Section 203.7.2.1, stated that a PDO was required when the IDO relied on assumptions that have not been justified and additional information could negate a previous determination that there is a reasonable expectation of operability. Contrary to the above, on March 4, 2014, the licensee failed to perform an adequate PDO to address the effects of low lube oil temperature on DG operability.
Because the finding was determined to be of very low safety significance and was entered into the licensees CAP as PIP C-14-2590, this violation is being treated as an NCV, consistent with Section 2.3.2 of the NRC Enforcement Policy: NCV 05000413/2014004-02, Failure to Adequately Implement a Prompt Determination of Operability for Diesel Generator Lube Oil Temperature.
4OA6 Meetings, Including Exit
On October 6, 2014, the resident inspectors presented the inspection results to Mr.
Kelvin Henderson and other members of licensee management. The inspectors verified that no proprietary information was retained by the inspectors or documented in this report.
4OA7 Licensee-Identified Violations
The following violation of very low safety significance (Green) was identified by the licensee and is a violation of NRC requirements which met the criteria of the NRC Enforcement Policy, for being dispositioned as a Non-Cited Violation.
- 10CFR50, Appendix B, Criterion XVI required in part that measures shall be established to assure that conditions adverse to quality are promptly identified and corrected. Significant conditions adverse to quality must be corrected to prevent recurrence. Contrary to the above, from 2006 to May, 2014, the licensee failed to prevent recurrence for a significance condition adverse to quality in that the licensee did not establish corrective actions for standby lube oil conditions that contributed to three DG bearing rotations discovered during maintenance inspections on the 1A and 2A DGs. The inspectors determined that the violation was of very low safety significance (Green) because the rotated bearings did not prevent the DGs from performing their safety function. The issue is documented in the licensees corrective action program as PIP C-14-2352.
ATTACHMENT:
SUPPLEMENTARY INFORMATION
KEY POINTS OF CONTACT
Licensee Personnel
- T. Arlow, Emergency Planning Manager
- D. Barker, Operations Manager
- D. Cantrell, Chemistry Manager
- T. Hamilton, General Manager, Nuclear Engineering
- R. Hart, Regulatory Affairs Manager
- K. Henderson, Site Vice-President
- H. Jarman, Assistant Operations Manager - Shift
- T. Jenkins, Maintenance Manager
- C. Kamilaris, Organizational Effectiveness Director
- B. Leonard, Training Manager
- R. Llewellyn, Operations Training Manager
- K. Phillips, Work Management Manager
- P. Simbrat, Regulatory Affairs Specialist
- T. Simril, Plant Manager
- J. Smith, Radiation Protection Manager
- W. Suslick, Director, Nuclear Engineering
- S. West, Director, Nuclear Plant Security
LIST OF REPORT ITEMS
Opened and Closed
Failure to implement fire impairment requirements for a degraded committed fire barrier (Section 1R05)
Failure to adequately implement a prompt determination of operability for diesel generator lube oil temperature (Section 4OA5)
Closed
NOED 14-2-001 to allow bearing replacement and testing of the 1A diesel generator (Section 4OA3)
Review of root cause analysis for the #7 bearing rotation and effectiveness of previous corrective actions (Section 4OA3)
Review of completed prompt determination of operability (PDO) and compensatory actions (Section 4OA5.2)
- 05000413/2014-001-00 LER
Condition prohibited by Technical Specifications and Notice of Enforcement Discretion due to misaligned connecting rod bearing on diesel generator 1A (Section 4OA3)