IR 05000369/2012002
| ML12117A398 | |
| Person / Time | |
|---|---|
| Site: | Mcguire, McGuire  |
| Issue date: | 04/26/2012 |
| From: | Bartley J NRC/RGN-II/DRP/RPB1 |
| To: | Repko R Duke Energy Carolinas |
| References | |
| IR-12-002 | |
| Download: ML12117A398 (25) | |
Text
UNITED STATES pril 26, 2012
SUBJECT:
MCGUIRE NUCLEAR STATION - NRC INTEGRATED INSPECTION REPORT 05000369/2012002 AND 05000370/2012002
Dear Mr. Repko:
On March 31, 2012, the U.S. Nuclear Regulatory Commission (NRC) completed an inspection at your McGuire Nuclear Station Units 1 and 2. The enclosed inspection report documents the inspection results which were discussed on April 5, 2012, with you and other members of your staff.
The inspection examined activities conducted under your licenses as they relate to safety and compliance with the Commissions rules and regulations and with the conditions of your licenses. The inspectors reviewed selected procedures and records, observed activities, and interviewed personnel.
The enclosed inspection report documents two NRC identified findings of very low safety significance (Green). One of these findings was determined to involve a violation of NRC requirements. The NRC is treating this violation as a non-cited violation (NCV) consistent with Section 2.3.2 of the NRC Enforcement Policy. If you contest this NCV, you should provide a written response within 30 days of the date of this inspection report, with the basis for your denial, to the Nuclear Regulatory Commission, ATTN.: Document Control Desk, Washington, D.C. 20555-0001; with copies to the Regional Administrator, Region II; the Director, Office of Enforcement, United States Nuclear Regulatory Commission, Washington, D.C. 20555-0001; and the NRC Resident Inspector at the McGuire Nuclear Station. 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 the McGuire Nuclear Station.
DEC 2 In accordance with 10 CFR 2.390 of the NRC's "Rules of Practice," a copy of this letter and its enclosure will be available electronically for public inspection in the NRC Public Document Room or from the Publicly Available Records (PARS) component of NRCs 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 By C. Rapp For/
Jonathan H. Bartley, Chief Reactor Projects Branch 1 Division of Reactor Projects Docket Nos.: 50-369, 50-370 License Nos.: NPF-9, NPF-17
Enclosure:
NRC Integrated Inspection Report 05000369/2012002 and 05000370/2012002 w/Attachment - Supplemental Information
REGION II==
Docket Nos.: 50-369, 50-370 License Nos.: NPF-9, NPF-17 Report Nos.: 05000369/2012002, 05000370/2012002 Licensee: Duke Energy Carolinas, LLC Facility: McGuire Nuclear Station, Units 1 and 2 Location: Huntersville, NC 28078 Dates: January 1, 2012, through March 31, 2012 Inspectors: J. Zeiler, Senior Resident Inspector J. Heath, Resident Inspector D. Jones, Senior Reactor Inspector (Section 1R07)
Approved by: Jonathan Bartley, Chief Reactor Projects Branch 1 Division of Reactor Projects Enclosure
SUMMARY OF FINDINGS
IR05000369/2012-002, IR05000370/2012-002; 01/01/2012 - 03/31/2012; McGuire Nuclear
Station; Fire Protection, Problem Identification and Resolution.
The report covered a three month period of inspection by two resident inspectors and a senior reactor inspector. Two Green findings, one of which was determined to involve a violation of NRC requirements, were identified. The significance of most findings is indicated by their color (Green, White, Yellow, Red) using Inspection Manual Chapter (IMC) 0609, Significance Determination Process (SDP). Cross-cutting aspects are determined using IMC 0310,
Components Within The Cross-Cutting Areas. Findings for which the SDP does not apply may be Green or be assigned a severity level after NRC management review. The NRC's program for overseeing the safe operation of commercial nuclear power reactors is described in NUREG-1649, Reactor Oversight Process.
Cornerstone: Mitigating Systems
- Green: An NRC-identified non-cited violation (NCV) of Technical Specification (TS) 5.4.1.d was identified for failure to maintain an operable fire assembly resulting in an unsealed pipe penetration through a 3-hour rated fire barrier wall separating the Unit 2 Train A/B motor driven auxiliary feedwater pump room from the Unit 2 mechanical penetration equipment room. The licensee reinstalled pipe caps on each end of the unsealed pipe.
The performance deficiency (PD) was more than minor because it was associated with the protection against external events attribute of the Mitigating Systems cornerstone and adversely affected the cornerstone objective in that the unsealed opening adversely impacted the ability of the fire barrier to perform its intended safety function. The finding was of very low safety significance because the fire barrier deficiency represented a low fire degradation rating. The finding was directly related to the cross-cutting area of Human Performance under the Procedural Compliance aspect of the Work Practices component because station personnel failed to follow fire protection impairment procedures for breaching a fire assembly. H.4(b) (Section 1R05)
- Green: A NRC-identified finding was identified for the failure to follow the sites corrective action program (CAP) procedure which required the initiation of a PIP for a degraded 2B emergency diesel generator (EDG) Bellofram seal. The degraded Bellofram seal contributed to the improper setup of the 2B EDG governor actuator which resulted in the 2B EDG not achieving the required 105 percent full power output.
The performance deficiency was more than minor because it was associated with the human performance attribute of the Mitigating Systems cornerstone and adversely impacted the cornerstone objective in that the capability of the EDG to provide continuous and adequate load margin was affected. The finding was of very low safety significance because it did not represent an actual loss of safety function of the system or train. The finding was directly related to the cross-cutting aspect of implements the CAP with a low threshold in the Corrective Action Program component in the area of the Problem Identification and Resolution because the licensee did not enter the condition into the CAP.
P.1(a) (Section 4OA2)
REPORT DETAILS
Summary of Plant Status
Unit 1 began the inspection period at approximately 100 percent rated thermal power (RTP) and operated at essentially full RTP for the entire inspection period.
Unit 2 began the inspection period at approximately 100 percent RTP and operated at essentially full RTP for the entire inspection period.
REACTOR SAFETY
Cornerstones: Initiating Events, Mitigating Systems, Barrier Integrity
1R04 Equipment Alignment
a. Inspection Scope
Partial Walkdowns: The inspectors performed a partial walkdown of the following four systems to assess the operability of redundant or diverse trains and components when safety equipment was inoperable. The inspectors focused on discrepancies that could impact the function of the system and potentially increase risk. The inspectors reviewed applicable operating procedures and walked down control systems components to verify selected breakers, valves, and support equipment were in the correct position to support system operation. Documents reviewed are listed in the Attachment.
- 2A motor driven auxiliary feedwater (MDCA) pump and Unit 2 turbine driven auxiliary feedwater (TDCA) pump while 2B MDCA pump was out of service for refurbishment of motor cooling water valve 2RN-170B
- 2A centrifugal charging pump (CCP) while 2B CCP was out of service for emergent outboard bearing seal leakage repair
- 1A spent fuel cooling (KF) pump while 1B KF pump was out of service for solenoid replacement on air handling unit cooling water supply
b. Findings
No findings were identified.
1R05 Fire Protection
a. Inspection Scope
Fire Protection Walkdowns: The inspectors walked down accessible portions of the following five plant areas to determine if they were consistent with the Updated Final Safety Analysis Report (UFSAR) and the fire protection program for defense in depth features. The features assessed included the licensees control of transient combustible material and ignition sources, fire detection and suppression capabilities, firefighting equipment, and passive fire features such as fire barriers. The inspectors also reviewed the licensees compensatory measures for fire deficiencies to determine if they were commensurate with the significance of the deficiency. The inspectors reviewed the fire plans for the areas selected to determine if it was consistent with the fire protection program and presented an adequate fire fighting strategy. Documents reviewed are listed in the Attachment.
- Unit 1 rod drive motor generator set room (Fire Area 22)
- Unit 2 rod drive motor generator set room (Fire Area 23)
- Unit 2 CCP and safety injection (NI) pump rooms on auxiliary building 716 elevation (Fire Area 4)
- Unit 2 Train A electrical switchgear and penetration rooms (Fire Areas 16-18)
- Unit 2 MDCA and TDCA pump rooms (Fire Areas 3 and 3A)
b. Findings
Introduction:
An NRC-Identified Green NCV of TS 5.4.1.d was identified for failure to maintain an operable fire assembly. A pipe penetration through a 3-hour rated fire barrier wall separating the Unit 2 Train A/B MDCA pump room from the Unit 2 mechanical penetration equipment room was not sealed with pipe caps as required.
Description:
On March 25, 2012, the inspectors identified a degraded 3-hour rated fire assembly in the wall between the Unit 2 Auxiliary Building 716 foot elevation Train A/B MDCA pump room (Fire Area 3) and the Unit 2 mechanical penetration equipment room (Fire Area 4). The inspectors observed in the Unit 2 MDCA pump room an open ended 4-foot section of rubber hose connected to a 1-inch diameter pipe that penetrated through fire assembly 2-716-108.1-26. The inspectors questioned the configuration on the opposite end of this 1-inch pipe which was located in the adjacent Unit 2 mechanical penetration room and it was discovered that the pipe end was open. The correct configuration required pipe caps to be installed on either end of the pipe to maintain an operable fire assembly. The licensee immediately restored the fire assembly to an operable condition via reinstallation of the required pipe caps.
The inspectors reviewed NSD 316, Fire Protection Impairment and Surveillance, Revision (Rev.) 11, and noted that the procedure required plant personnel that either have knowledge of, or as part of approved maintenance activities that need to intentionally breach committed fire barriers, were responsible for notifying the Work Control Center to ensure appropriate fire barrier impairment controls were implemented.
The licensees initial investigation did not identify any open or recently completed fire impairments entered for this fire barrier breach; however, it was believed that recent maintenance had been conducted that necessitated opening of the pipe to transfer fluids.
Analysis:
The inspectors determined the licensees failure to maintain an operable fire assembly was a PD. The PD was more than minor because it was associated with the protection against external events attribute of the Mitigating Systems cornerstone and adversely affected the cornerstone objective in that the unsealed opening impacted the ability of the fire barrier to perform its intended safety function. Using NRC Inspection IMC 0609, Significance Determination Process, Appendix F, Fire Protection Significance Determination Process, Phase 1 Worksheet, the finding was determined to be of very low safety significance because the fire barrier deficiency represented a low fire degradation rating based on the small diameter of the unsealed opening. The finding was directly related to the cross-cutting area of Human Performance under the Procedural Compliance aspect of the Work Practices component because station personnel failed to follow fire protection impairment procedures for breaching a fire assembly. H.4(b)
Enforcement:
TS 5.4.1.d, Procedures, required, in part, that applicable procedures covered by commitments contained in UFSAR Chapter 16.0, Selected Licensee Commitments (SLC), be established, implemented, and maintained. SLC 16.9.5, Fire Rated Assemblies, required, in part, that all fire assemblies and their associated sealing devices separating post-fire safe shutdown equipment, be operable at all times or fire impairment/compensatory controls shall be implemented. NSD 316, Fire Protection Impairment and Surveillance, Rev. 11, required that specific fire impairment/compensatory controls to be implemented for inoperable fire assemblies.
Contrary to the above, on March 25, 2012, the licensee failed to adequately implement NSD 316, in that, fire assembly 2-716-108.1-26 was found inoperable without implementing fire impairment control measures. Because this violation was determined to be of very low safety significance and has been entered into the licensees CAP as PIP M-12-2226, it is being treated as an NCV consistent with Section 2.3.2 of the NRC Enforcement Policy: NCV 05000370/2012002-01, Failure to Maintain Operable Fire Assembly in Unit 2 Auxiliary Feedwater Pump Room.
1R07 Heat Sink Performance
a. Inspection Scope
Triennial Review of Heat Sink Performance: The inspectors reviewed completed surveillances, vendor manual information, associated calculations, performance test results, and cooler inspection results associated with the following three heat removal components for the last three years. These components were chosen based on their safety-related functions and risk significance.
- Unit 1 and 2 control room chiller condenser heat exchangers
- Unit 2 residual heat removal (ND) exchangers
- Standby Nuclear Service Water Pond (SNSWP)
For the control room chiller condenser heat exchangers, the inspectors determined whether testing, inspection, maintenance, and monitoring of biofouling and macrofouling programs were adequate to ensure proper heat transfer. This was accomplished by determining whether the test method of measuring differential pressure was appropriate, the test conditions were consistent with the selected methodology, the test acceptance criteria were consistent with the design basis values, and reviewing results of heat exchanger performance testing. The inspectors also determined whether the test results appropriately considered differences between testing conditions and design conditions, the frequency of testing based on trending of test results was sufficient to detect degradation prior to loss of heat removal capabilities below design basis values, and test results considered test instrument inaccuracies and differences.
The inspectors determined whether the methods used to inspect and clean heat exchangers were consistent with as-found conditions identified and expected degradation trends; the licensees inspection and cleaning activities had established acceptance criteria; and the as-found results were recorded, evaluated, and appropriately dispositioned such that the as-left condition was acceptable. In addition, the inspectors determined whether the condition and operation of the control room chiller condenser heat exchanger was consistent with design assumptions in heat transfer calculations and as described in the UFSAR. This included determining whether the number of plugged tubes was within pre-established limits based on capacity and heat transfer assumptions. In addition, eddy current test reports and visual inspection records were reviewed to determine the structural integrity of the heat exchanger.
For the Unit 2 ND heat exchanger, the inspectors determined whether the condition and operation of the heat exchanger was consistent with design assumptions in heat transfer calculations and as described in the UFSAR. This included determining whether the number of plugged tubes was within pre-established limits based on capacity and heat transfer assumptions. The inspectors determined whether the licensee maintained a chemical treatment program for corrosion control on the component cooling side of the heat exchanger.
For the SNSWP, the inspectors determined whether performance of the ultimate heat sink (UHS), and its subcomponents such as piping, intake screens, pumps, valves, etc.
was appropriately evaluated by tests or other equivalent methods to ensure availability and accessibility to the in-plant cooling water systems for the last three years. The inspectors determined whether the licensees inspection of the UHS was thorough and of sufficient depth to identify degradation of the shoreline protection or loss of structural integrity. This included determination of whether vegetation present along the slopes was trimmed, maintained, and not adversely impacting the embankment along with the review of the independent consultant inspection report dated July 29, 2010. In addition, the inspectors determined whether macrofouling was adequately monitored, trended, and controlled by the licensee to prevent clogging. The inspectors determined whether the licensees biocide treatments for biotic control were adequately conducted and whether the results were adequately monitored, trended, and evaluated. The inspectors also performed a system walkdown of the SNSWP to determine whether the licensees assessment on structural integrity and component functionality was adequate.
The inspectors reviewed the licensees operation of the service water system and UHS.
This included a review of licensees procedures for a loss of the service water system, or UHS, and the verification that level instrumentation, which is relied upon for decision making, was available and functional. The inspectors performed a system walkdown on service water and/or closed cooling water systems to determine whether the licensees assessment on structural integrity was adequate. In addition, the inspectors reviewed condition reports related to the heat exchangers/coolers and heat sink performance issues to determine whether the licensee had an appropriate threshold for identifying issues, and to determine whether the licensee implemented effective corrective actions.
Documents reviewed are listed in the Attachment.
b. Findings
No findings were identified.
1R11 Licensed Operator Requalification Program
a. Inspection Scope
Quarterly Resident Inspector Activity Review: On February 15, 2012, the inspectors observed licensed operators in the plants simulator during an emergency preparedness training drill. The training drill scenario involved a turbine trip on high vibration followed by an Anticipated Transient Without Scram, and a subsequent steam generator tube rupture. 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 critique to determine whether the licensee identified deficiencies and discrepancies that occurred during the simulator training. Documents reviewed are listed in the Attachment.
Quarterly Resident Inspector Licensed Operator Performance Review: On January 11, 2012, the inspectors observed operators in the main control room and assessed their performance during a manual main turbine load decrease and manual control rod manipulations to support scheduled testing of the Unit 2 TDCA pump which can affect reactor power via use of main steam. 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) charging unavailability for performance;
- (6) balancing reliability and unavailability;
- (7) trending key parameters for condition monitoring; (8)classification and reclassification in accordance with 10 CFR 50.65(a)(1) or (a)(2); and
- (9) 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). 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
.
- Steam generator power-operated relief valves 2SV-13 AB and 2SV-1AB failure to meet initial valve stroke test acceptance criteria (PIPs M-11-0889 and M-12-1052)
b. Findings
No findings were identified.
1R13 Maintenance Risk Assessments and Emergent Work Control
a. Inspection Scope
The inspectors reviewed the licensees risk assessments and the risk management actions used to manage risk for the plant configurations associated with the five activities listed below. The inspectors assessed whether the licensee performed adequate risk assessments, and implemented appropriate risk management actions when required by 10 CFR 50.65(a)(4). For emergent work, the inspectors verified that any increase in risk was promptly assessed, that appropriate risk management actions were promptly implemented, and that work activities did not place the plant in unacceptable configurations. Documents reviewed are listed in the Attachment.
- Planned Yellow risk for 2B MDCA pump motor cooling water valve 2RN-170B actuator refurbishment
- Emergent risk for work associated with replacement of outboard bearing mechanical seal of 2B CCP due to excessive leakage
- Planned Yellow risk for standby shutdown facility diesel generator and standby makeup pump and Unit 1 TDCA pump
- Planned Orange risk for 2B nuclear service water (RN) system during Phase 3 strainer modification and 2B EDG complex work activities
- Emergent Yellow risk for repair of 1B EDG following failure to start on manual start testing
b. Findings
No findings were identified.
1R15 Operability Determinations and Functionality Assessments
a. Inspection Scope
The inspectors reviewed the six technical evaluations listed below to determine whether TS operability was properly justified and the subject component or system remained available such that no unrecognized increase in risk occurred. The inspectors reviewed any compensatory measures taken for degraded SSCs to determine whether the measures were in-place and adequately compensated for the degradation. For the degraded SSCs, or those credited as part of compensatory measures, the inspectors reviewed the UFSAR to determine whether the measures resulted in changes to the licensing basis functions, as described in the UFSAR, and whether a license amendment was required per 10 CFR 50.59. Documents reviewed are listed in the Attachment.
- PIP M-12-0102, 125 volt direct current vital battery post seals cracks and corrosion
- PIP M-12-0106, Standby Nuclear Service Water Pond thermal analysis uncertainties
- PIP M-12-1428, Unit 2 partial momentary loss of reactor coolant pump seal injection
b. Findings
No findings were identified.
1R18 Plant Modifications
a. Inspection Scope
The inspectors reviewed the following two modifications to verify the adequacy of the modification packages and 10 CFR 50.59 screenings. Each modification was evaluated against the TS, UFSAR, and licensee design bases documents for the systems affected to ensure the modification did not adversely affect the availability, reliability, and functional capability of important SSCs. Documents reviewed are listed in the
.
Permanent Modification
b. Findings
No findings were identified.
1R19 Post-Maintenance Testing
a. Inspection Scope
The inspectors reviewed the six 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.
- 2B MDCA pump motor cooler control valve 2RN-170B retest following valve actuator replacement
- 1B EDG battery charger performance test following Part 21 relay replacement
- 2B CCP retest following outboard bearing mechanical seal replacement
- 2B RN to 2B ND pump motor air handling unit inlet isolation valve 2RN-231B/2RNSV2130 retest following solenoid replacement
- 1B NI pump breaker functional verification following 1ETB9 breaker and auxiliary switch replacement
- 2B EDG retest following routine minor maintenance
b. Findings
No findings were identified.
1R22 Surveillance Testing
a. Inspection Scope
For the five surveillance tests identified below, the inspectors witnessed testing and reviewed the test data, to determine if the SSCs involved in these tests satisfied the requirements described in the TS, UFSAR, and applicable licensee procedures. In addition, the inspectors verified that the tests demonstrated that the SSCs were capable of performing their intended safety functions. Documents reviewed are listed in the
.
Surveillance Tests
- IP/0/A/3061/007, GNB Vital Battery and Terminal Post Inspection, Rev. 23
- PT/2/A/4350/002A, Diesel Generator 2A Operability Test, Rev. 86
- PT/1/A/4252/001, #1 TDCA Pump Performance Test, Rev. 123
- PT/2A/4600/001, RCCA Movement Test, Rev. 41 In-Service Tests
- PT/2/A/4252/001, #2 TDCA Pump Performance Test, Rev. 111
b. Findings
No findings were identified.
Cornerstone: Emergency Preparedness
1EP6 Drill Evaluation
a. Inspection Scope
On February 15, 2012, the inspectors reviewed and observed the performance of a quarterly licensee emergency preparedness training drill involving an Anticipated Transient Without Scram followed by a steam generator tube rupture. The inspectors assessed the licensee emergency procedure usage, emergency plan classifications, notifications, and protective action recommendation development. The inspectors evaluated the adequacy of the licensees conduct of the drill and post-drill critique performance. The inspectors verified that the drill critique identified drill performance weaknesses and entered these items into the licensees CAP. Documents reviewed are listed in the Attachment.
b. Findings
No findings were identified.
4OA1 Performance Indicator (PI) Verification
a. Inspection Scope
The inspectors sampled licensee data to confirm the accuracy of reported PI data for the following six indicators during the four quarters of 2011. To determine the accuracy of the PI data reported during that period, the inspectors compared the licensees basis in reporting each data element to the PI definitions and guidance contained in NEI 99-02, Regulatory Assessment Indicator Guideline, Rev. 6.
Initiating Events Cornerstone
- Unplanned Scrams per 7000 Critical Hours (Units 1 and 2)
- Unplanned Scrams with Complications (Units 1 and 2)
- Unplanned Power Changes per 7000 Critical Hours (Units 1 and 2)
The inspectors reviewed the documents listed in the Attachment to determine whether the licensee had adequately identified the number of scrams and unplanned power changes greater than 20 percent that occurred during the previous four quarters. The inspectors compared this number to the number reported for the PI during the current quarter. The inspectors also reviewed the accuracy of the number of critical hours reported and the licensees basis for determining that there were not complications for each of the reported reactor scrams. In addition, the inspectors interviewed licensee personnel associated with the PI data collection, evaluation, and distribution.
Documents reviewed are listed in the Attachment.
b. Findings
No findings were identified.
4OA2 Problem Identification and Resolution
a. Inspection Scope
Review of Items Entered into the CAP: 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 CAP. This was accomplished by reviewing copies of condition reports, attending some daily screening meetings, and accessing the licensees computerized CAP database.
Annual Sample Review of Operator Workarounds (OWAs): The inspectors reviewed the licensees list of identified OWAs, equipment deficiencies, and plant concerns to determine whether any new items since the previous review conducted in 2011 would adversely affect any mitigating system function or affect the operators ability to implement abnormal or emergency operating procedures. The inspectors reviewed the classification assigned to the identified OWAs to ensure they were properly prioritized based on the licensees program requirements. For high priority OWAs where compensatory actions were developed, the inspectors verified the feasibility of implementing these prescribed actions. The inspectors verified that long term corrective actions were developed to adequately address the underlying issues identified in the OWAs. In addition, the inspectors attended a quarterly OWA meeting between operations, engineering, and chemistry personnel to discuss the status of open OWAs and new OWA candidates. Documents reviewed are listed in the Attachment.
Selected Issue Follow-up: The inspectors reviewed the issue listed below in detail to evaluate the effectiveness of the licensees corrective actions for important safety issues.
- PIP M-11-5505, 2B EDG inability to reach overload operation during testing on August 2, 2011 The inspectors assessed whether the issue was properly identified; documented accurately and completely; properly classified and prioritized; adequately considered extent of condition, generic implications, common cause, and previous occurrences; adequately identified the root cause/apparent cause; and identified appropriate and timely corrective actions. The inspectors evaluated the licensee documents against the requirements of the licensees CAP and implementing procedures, and 10 CFR 50, Appendix B. Documents reviewed are listed in the Attachment.
b. Findings and Observations
The licensee determined the root cause of the issue associated with PIP M-11-5505 was a lack of documented guidance in the original equipment manufacturer drawings for replacing the mechanical governor actuator in March 2011. The inspectors determined that, in general, the problem identification, root cause analysis, and corrective actions were adequate. However, the causal analysis did not consider the failure to enter into the CAP and evaluate the Bellofram seal leak, a condition adverse to quality, when the leak was first identified in February 2011. The degraded Bellofram seal contributed to the improper setup of the 2B EDG governor actuator that was replaced in March 2011.
The inspectors determined the failure to adequately evaluate the impact of the Bellofram seal leak through the CAP program was a contributing cause of the event.
Failure to Follow CAP Procedure Involving a Condition Adverse to Quality
Introduction:
A Green NRC-identified finding was identified for the failure to follow the sites CAP procedure which required the initiation of a PIP for a degraded 2B EDG Bellofram seal. The Bellofram seal leak contributed to the improper setup of the 2B EDG governor actuator which resulted in the 2B EDG not achieving the required 105 percent full power output.
Description:
On February 15, 2011, during a 2B EDG 24-hr surveillance run, testing revealed higher than normal peak firing pressures at which point the licensee confirmed the presence of a leaking Bellofram seal. The degraded seal condition was documented and evaluated in work request (WR) 01027942. The licensee scheduled the seal repair for July 2011 following the Unit 2 outage. The licensee justified operability of the 2B EDG within the work request based on the fact that the engine met all of its surveillance requirements. The inspectors noted that no PIP was generated for this degraded condition.
The inspectors reviewed NSD 208, Problem Investigation Program, and determined that the leaking Bellofram seal was a condition adverse to quality as described in Appendix A, Guidelines for Determining Significance Level. NSD 208 required a PIP be generated for conditions adverse to quality involving degraded safety-related equipment.
Generating a PIP would have subjected the degraded condition to formal evaluation, resolution, and additional reviews in accordance with the requirements of NSD 208. The evaluation of a condition adverse to quality through a WR did not meet the requirements of the licensees CAP concerning degradations of safety-related equipment. The inspectors concluded that the licensee failed to address how the seal leak could impact the engine throughout continued operation and the governor replacement setup in March 2011 by not entering the issue into the CAP.
2B EDG load was achieved with less than normal fuel delivery to the engine because the Bellofram seal allowed more air charge in the cylinders which masked the lower than expected fuel rack operation from the governor replacement. When the seal was subsequently replaced in July 2011, the air charge in the cylinders returned to normal and consequently the engine required more fuel to achieve the same power output. At this point, the 2B EDG was not able to achieve overload until the condition was discovered and corrected following testing on August 2, 2011.
Analysis:
The inspectors determined that the licensees failure to follow NSD 208 and initiate a PIP for a condition adverse to quality associated with the 2B EDG Bellofram seal leak was a PD. The PD was determined to be more than minor because it was associated with the Mitigating Systems cornerstone attribute of Human Performance and adversely impacted the cornerstone objective in that the 2B EDG was not able to provide continuous and adequate load margin. The finding was evaluated using IMC 0609, 4, Phase 1, and determined to be of very low safety significance because it did not represent an actual loss of safety function of the system or train because the 2B EDG was capable of achieving 100 percent of design basis accident load. The finding was directly related to the cross-cutting aspect of implements the CAP with a low threshold in the Corrective Action Program component in the area of the Problem Identification and Resolution because the licensee did not enter the condition into the CAP. P.1(a).
Enforcement:
The inspectors determined that this finding did not involve a violation of NRC requirements and is not subject to enforcement action. Because of the very low safety significance, this finding will be identified as Finding (FIN)05000370/2012002-02, Failure to Enter Condition Adverse to Quality into the CAP.
4OA3 Followup of Events and Notices of Enforcement Discretion
.1 (Closed) Licensee Event Report (LER) 05000370/2011-001, Emergency Diesel
Generator 2B Inability to Achieve Overload Operation The licensee discovered that the 2B EDG was incapable of achieving overload operation during performance of a quarterly surveillance test. The inspectors reviewed the LER, PIP M-11-5505, and the associated root cause evaluation. Licensee corrective actions included revising their procedures to ensure that the engine fuel racks are properly adjusted following any governor actuator replacement and to conduct overload testing any time that a Bellofram seal was replaced. The inspectors determined that the licensees planned corrective actions were adequate; however, the licensee failed to address not initiating a PIP when the degraded Bellofram seal was initially identified.
This LER is further discussed in Section 4OA2.
.2 (Closed) LER 05000370/2011-003, Unit 2 Manually Tripped When Control Rod did not
Respond as Expected during Control Rod Movement Testing The inspectors reviewed the subject LER and PIPs M-11-2694 and M-11-6406 associated with the issue to verify the LER accuracy and appropriateness of corrective actions. The failure to originally submit an LER for a valid reactor protection system actuation was previously addressed in NCV 05000369, 370/2011003-02. No new findings were identified.
4OA5 Other Activities
a. Inspection Scope
Quarterly Resident Inspector Observations of Security Personnel and Activities: During the inspection period, the inspectors conducted observations of security force personnel and activities to ensure that the activities were consistent with licensee security procedures and regulatory requirements relating to nuclear plant security. These observations took place during both normal and off-normal plant working hours. These quarterly resident inspector observations of security force personnel and activities did not constitute any additional inspection samples. Rather, they were considered an integral part of the inspectors' normal plant status review and inspection activities.
b. Findings
No findings were identified.
4OA6 Meetings, Including Exit
On April 5, 2012, the resident inspectors presented the inspection results to Mr. Regis T.
Repko and other members of his staff. The inspectors confirmed that proprietary information was not provided or examined during the inspection.
ATTACHMENT:
SUPPLEMENTAL INFORMATION
KEY POINTS OF CONTACT
Licensee
- R. Abbott, Licensing
- D. Brenton, Plant Operations Superintendent
- D. Brewer, Safety Assurance Manager
- S. Capps, Station Manager
- J. Gabbert, Chemistry Manager
- J. Hicks, Maintenance Superintendent
- S. Karriker, BOP Systems Engineering Nuclear Section Manager
- N. Kunkel, Work Control Superintendent
- S. Mooneyhan, Radiation Protection Manager
- J. Nolin, Mechanical and Civil Engineering Manager
- R. Repko, Vice President - McGuire Nuclear Station
- S. Russ, Security Manager
- P. Schuerger, Training Manager
- J. Smith, RNDB Nuclear Section Manager
- S. Snider, Engineering Manager (Acting)
LIST OF REPORT ITEMS
Opened and Closed
- 05000370/2012002-01 NCV Failure to Maintain Operable Fire Assembly in Unit 2 Auxiliary Feedwater Pump Room (1R05)
- 05000370/2012002-02 FIN Failure to Enter Condition Adverse to Quality into the CAP (4OA2)
Closed
- 05000370/2011-001 LER Emergency Diesel Generator 2B Inability to Achieve Overload Operation (4OA3.1)
- 05000370/2011-003 LER Unit 2 Manually Tripped When Control Rod did not Respond as Expected during Control Rod Movement Testing (4OA3.2)