IR 05000395/2010003
| ML102080275 | |
| Person / Time | |
|---|---|
| Site: | Summer  |
| Issue date: | 07/27/2010 |
| From: | Gerald Mccoy NRC/RGN-II/DRP/RPB5 |
| To: | Gatlin T South Carolina Electric & Gas Co |
| References | |
| IR-10-003 | |
| Download: ML102080275 (27) | |
Text
UNITED STATES uly 27, 2010
SUBJECT:
VIRGIL C. SUMMER NUCLEAR STATION - NRC INTEGRATED INSPECTION REPORT 05000395/2010003
Dear Mr. Gatlin:
On June 30, 2010, the U.S. Nuclear Regulatory Commission (NRC) completed an inspection at your Virgil C. Summer Nuclear Station. The enclosed inspection report documents the inspection results, which were discussed on July 20, 2010, with you 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.
This report documents one self-revealing finding of very low safety significance (Green) which was determined to be a violation of NRC requirements. However, because of the very low safety significance and because it was entered into your corrective action program, the NRC is treating the finding as a non-cited violation (NCV) consistent with Section VI.A.1 of the NRCs Enforcement Policy. If you contest the NCV, you should provide a response within 30 days of the date of this inspection report, with the basis for your denial, to the United States Nuclear Regulatory Commission, ATTN: Document Control Desk, Washington DC 20555-0001, with copies to the Regional Administrator, Region II; the Director, Office of Enforcement, United States Nuclear Regulatory Commission, Washington, DC 20555-0001; and the NRC Resident Inspector at the Virgil C. Summer Nuclear Station. In addition, 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, RII, and the NRC Senior Resident Inspector at the Virgil C. Summer Nuclear Station.
SCE&G 2 In accordance with 10 CFR 2.390 of the NRCs 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 document 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/
Gerald J. McCoy, Chief Reactor Projects Branch 5 Division of Reactor Projects Docket No.: 50-395 License No.: NPF-12
Enclosure:
Inspection Report 05000395/2010003 w/Attachment: Supplemental Information
REGION II==
Docket No.: 50-395 License No.: NPF-12 Report No.: 05000395/2010003 Licensee: South Carolina Electric & Gas (SCE&G) Company Facility: Virgil C. Summer Nuclear Station Location: P.O. Box 88 Jenkinsville, SC 29065 Dates: April 1, 2010 through June 30, 2010 Inspectors: J. Zeiler, Senior Resident Inspector J. Polickoski, Resident Inspector Approved by: Gerald J. McCoy, Chief Reactor Projects Branch 5 Division of Reactor Projects Enclosure
SUMMARY OF FINDINGS
IR 05000395/2010003; 04/01/2010 - 06/30/2010: Virgil C. Summer Nuclear Station; Event
Followup.
The report covered a 3-month period of inspection by resident inspectors. One Green finding, which was a non-cited violation (NCV), was 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). The cross-cutting aspect was 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 NRCs 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-Revealing Findings
Cornerstone: Initiating Events
- Green.
A Green self-revealing non-cited violation (NCV) of TS 6.8.1.a was identified for the failure to establish adequate procedural tagging controls of safety and non-safety related electrical ground protection equipment which contributed to the main power transformer being energized while electrical ground protection equipment was still installed in three 7.2 kV Balance of Plant (BOP) switchgear breaker cubicles.
This condition resulted in a complete loss of BOP power due to the faults to ground, significant arc flashing, and subsequent fires in each of the three switchgear cubicles requiring onsite and offsite fire brigade response and the declaration of an UE. The finding was entered into the licensees corrective action program as condition report CR-09-05093.
The inspectors determined that the licensees failure to develop an adequate station tagout procedure for controlling the configuration of safety and non-safety related ground protection equipment was a performance deficiency that was within the licensees ability to foresee and correct. While this event involved the mis-configuration of ground protection in non-safety-related BOP switchgear, the same station tagout procedural requirements apply to the control of safety-related equipment. This finding is more than minor because the failure to properly control the configuration of safety and non-safety related ground protection electrical equipment, if left uncorrected, would have the potential to lead to a more significant safety concern. In addition, the finding is associated with the protection against external factors attribute of the initiating events cornerstone and affected the cornerstone objective to limit the likelihood of events that upset plant stability and challenge critical safety functions during shutdown, in that, the failure to properly control the configuration of the ground protection equipment resulted in fires in three switchgear cubicles requiring onsite and offsite fire brigade response actions and the declaration of an UE. Since this problem occurred while the station was in cold shutdown (Mode 5) with the pressurizer solid and all three reactor coolant pumps initially bumped, NRC Inspection Manual Chapter (IMC) 0609, Significance
Determination Process, Appendix G, Shutdown Operations Significance Determination Process, was used to assess the significance of this finding. Using Phase 1 of Appendix G, the finding was determined to be of very low significance (Green) because it did not result in an actual loss of offsite power event nor degrade the licensees ability to cope with such an event since both emergency diesel generators, the dedicated offsite AC power, and alternate AC power sources remained available. This finding involved the cross-cutting area of human performance, the component of resources, and the aspect of complete, accurate and up-to-date procedures, H.2(c), because the licensee failed to establish adequate station tagout procedures for controlling the installation and removal of safety and non-safety related ground protection equipment. (Section 4OA3)
Licensee-Identified Violations
None
REPORT DETAILS
Summary of Plant Status
The unit began the inspection period at full Rated Thermal Power (RTP). On April 2, 2010, a shutdown was initiated in accordance with Technical Specifications due to the inoperability of the B emergency feedwater motor driven feedwater flow control valve FCV-03541-EF. The power descent was stopped at 86 percent following restoration of the valve to an operable condition. The unit was returned to full RTP later that same day. On April 23, 2010, power was reduced to 88 percent to conduct main turbine valve testing and tuning of the digital controllers to the feedwater regulating valves. The unit was returned to full RTP that same day. On June 1, 2010, power was reduced to 89 percent following the unexpected overspeed trip of the C main feedwater pump. The unit was returned to full RTP on June 3, 2010, following replacement of a failed control card associated with the C main feedwater pump control system. The unit operated at full RTP for the remainder of the period.
REACTOR SAFETY
Cornerstones: Initiating Events, Mitigating Systems, Barrier Integrity
1R01 Adverse Weather Protection
.1 Seasonal Weather Susceptibilities
a. Inspection Scope
The inspectors performed one adverse weather inspection for readiness of hot weather.
The inspectors verified the licensee had implemented applicable sections of operations administrative procedure (OAP)-109.1, Revision 2D, Guidelines for Severe Weather.
The inspectors walked down risk-significant equipment areas including the emergency diesel generator (EDG) rooms and service water pump house (SWPH) and verified the proper operation of cooling systems for the associated equipment in these areas. Also, the inspectors reviewed licensee plant computer data associated with area and equipment temperatures to verify the values were within expected operational ranges to prevent any challenge to equipment operation. The inspectors reviewed the licensees corrective action program (CAP) database to verify that high temperature weather related problems were being identified at the appropriate level, entered into the CAP, and appropriately resolved.
b. Findings
No findings were identified.
.2 Offsite and Alternate Alternating Current (AC) Power
a. Inspection Scope
The inspectors evaluated the readiness of the offsite and alternate AC power systems by reviewing the licensees procedures that address measures to monitor and maintain the availability and reliability of the offsite and alternate AC power systems. The procedures reviewed included those involved with the communication protocols between the plant and transmission system operator to verify that the appropriate information was being exchanged when issues arose that could impact the offsite power system. In addition, the inspectors performed a walkdown of electrical equipment in the switchyard and associated relay control building to ensure any degradations or adverse material conditions were identified in the licensees CAP and were being appropriately addressed in a manner commensurate with their significance. The documents reviewed during this inspection are listed in the attachment.
b. Findings
No findings were identified.
.3 Actual Adverse Weather Conditions
a. Inspection Scope
The inspectors performed an impending adverse weather inspection to review the licensees overall preparations and protection of risk-significant systems in response to a tornado warning in Fairfield County. The inspectors verified the licensee had implemented applicable sections of OAP-109.1, and emergency plan procedure (EPP)-
015, Revision 17, Natural Emergency. The inspectors performed a yard walkdown for continuing heavy thunderstorm conditions. Licensee response actions and weather report updates were monitored until the adverse weather conditions were over.
b. Findings
No findings were identified.
1R04 Equipment Alignment
.1 Partial System Walkdowns
a. Inspection Scope
The inspectors conducted three partial equipment alignment walkdowns which are listed below, to evaluate the operability of selected redundant trains or backup systems with the other train or system inoperable or out of service (OOS). Correct alignment and operating conditions were determined from the applicable portions of drawings, system operating procedures (SOPs), final safety analysis report (FSAR), and technical specifications (TS). The inspections included review of outstanding maintenance work orders (WOs) and related condition reports (CRs) to verify that the licensee had properly identified and resolved equipment alignment problems that could lead to the initiation of an event or impact mitigating system availability. Documents reviewed are listed in the attachment.
- A and B motor-driven emergency feedwater pumps (MDEFWP) while the turbine driven emergency feedwater pump (TDEFWP) was OOS for scheduled maintenance
- A residual heat removal (RHR) pump while B RHR was OOS for scheduled preventive maintenance
b. Findings
No findings were identified.
.2 Complete System Walkdown
a. Inspection Scope
The inspectors performed a detailed review and walkdown of the B component cooling water system to identify any discrepancies between the current operating system equipment lineup and the designed lineup. This walkdown included accessible areas of the auxiliary and intermediate buildings and the equipment alignment configuration as indicated from valves, pumps, and control room equipment status lights. In addition, the inspectors reviewed standard operating procedures, applicable sections of the FSAR, design basis document, plant drawings, completed surveillance procedures, outstanding WOs, system health reports, and related CRs to verify that the licensee had properly identified and resolved equipment problems that could affect the availability and operability of the system. Documents reviewed are listed in the attachment to this report.
b. Findings
No findings were identified.
1R05 Fire Protection
a. Inspection Scope
The inspectors reviewed recent CRs, WOs, and impairments associated with the fire protection system. The inspectors reviewed surveillance activities to determine whether they supported the operability and availability of the fire protection system. The inspectors assessed the material condition of the active and passive fire protection systems and features and observed the control of transient combustibles and ignition sources. The inspectors conducted routine inspections of the following five areas (respective fire zones also noted):
- Auxiliary building (AB), 374 elevation (fire zones AB-1.1, 1.2, 1.3)
- Intermediate building (IB), 412 elevation (fire zones IB-1.3 and IB-1.5)
- TDEFWP room (fire zone IB-25.2)
- A and B EDG rooms (fire zones DG-1.1/1.2 and DG-2.1/2.2)
- SWPH (fire zones SWPH-1, 3, 4, 5.1, and 5.2)
b. Findings
No findings were identified.
1R06 Flood Protection Measures
a. Inspection Scope
The inspectors reviewed and walked down all AB and IB radiological controlled area rooms credited for flood mitigation to determine consistency with design requirements, FSAR, and flood analysis documents. Risk significant structures, systems, and components (SSCs) in these areas included RHR pump rooms, recycle holdup tank room, AB sump, east penetration room, blowdown system sump and miscellaneous waste drain tank. The inspectors reviewed the licensees CAP database to verify that internal flood protection problems were being identified at the appropriate level, entered into the CAP, and appropriately resolved.
b. Findings
No findings were identified.
1R07 Heat Sink Performance
a. Inspection Scope
The inspectors conducted one heat sink performance sample. The inspectors observed aspects of the as-found condition, cleaning, and eddy-current testing of the B EDG intercooler heat exchanger following its opening for maintenance during an extended EDG 18-month outage during the week of May 17, 2010. The inspectors also reviewed the results of the heat exchanger eddy-current testing and the final test report provided by the testing contractor.
b. Findings
No findings were identified.
1R11 Licensed Operator Requalification Program
a. Inspection Scope
On June 7, 2010, the inspectors observed the performance of senior reactor operators and reactor operators on the plant simulator during licensed operator requalification training. The scenario, (LOR-SA-008) involved failure of a turbine first stage pressure instrument, overheating of unit auxiliary transformer XTF-2, trip of the B EDG, and subsequent loss of all AC electrical power. The inspectors assessed overall crew performance, communications, oversight of supervision, and the evaluators' critique.
The inspectors verified that any significant training issues were appropriately captured in the licensees CAP.
b. Findings
No findings were identified.
1R12 Maintenance Effectiveness
a. Inspection Scope
The inspectors evaluated two equipment issues described in the CRs listed below to verify the licensees effectiveness with the corresponding preventive or corrective maintenance associated with SSCs. The inspectors reviewed Maintenance Rule (MR)implementation to verify that component and equipment failures were identified, entered, and scoped within the MR program. Selected SSCs were reviewed to verify proper categorization and classification in accordance with 10 CFR 50.65. The inspectors examined the licensees 10 CFR 50.65(a)(1) corrective action plans to determine if the licensee was identifying issues related to the MR at an appropriate threshold and that corrective actions were established and effective. The inspectors review also evaluated if maintenance preventable functional failures (MPFFs) or other MR findings existed that the licensee had not identified.
The inspectors reviewed the licensees controlling procedures, i.e., engineering services procedure (ES)-514, Revision 4, Maintenance Rule Implementation, and the Virgil C.
Summer Important To Maintenance Rule System Function and Performance Criteria Analysis, to verify consistency with the MR requirements.
- CR-09-04134, A service water booster pump (SWBP) breaker difficult to rack out
- CR-09-04972, C reactor coolant pump (RCP) vibration probe found damaged during pump and instrument maintenance
b. Findings
No findings were identified.
1R13 Maintenance Risk Assessments and Emergent Work Control
a. Inspection Scope
The inspectors evaluated, as appropriate, for the five selected work activities listed below:
- (1) the effectiveness of the risk assessments performed before maintenance activities were conducted;
- (2) the management of risk;
- (3) that, upon identification of an unforeseen situation, necessary steps were taken to plan and control the resulting emergent work activities; and,
- (4) that emergent work problems were adequately identified and resolved. The inspectors evaluated the licensees work prioritization and risk characterization to determine, as appropriate, whether necessary steps were properly planned, controlled, and executed for the planned and emergent work activities.
- Work Week 2010-17: risk assessment for scheduled maintenance and testing on the TDEFWP (yellow risk); switchyard electrical manhole inspection; B RHR pump preventive maintenance (yellow risk); and, a planned unit down power to 90 percent to perform main turbine valve testing and feedwater regulating valve control circuitry tuning
- Work Week 2010-19: risk assessment for scheduled maintenance and testing for the 18-month extended outage on the A EDG (yellow risk); C chiller preventive maintenance; emergent maintenance on the A feedwater regulating valve feedback transducer; and, maintenance activities during a tornado warning in Fairfield County
- Work Week 2010-21: risk assessment for scheduled maintenance and testing for the 18-month extended outage on the B EDG (yellow risk); instrument air compressor replacement modification; and, TDEFWP testing
- Work Week 2010-22: risk assessment for scheduled maintenance and testing on the reactor make-up water system; trenching near the alternate AC power buried line; and, emergent maintenance on offsite power transmission lines to replace rotted poles
- Work Week 2010-23: risk assessment for scheduled maintenance on A EDG; repairs to the control building to turbine building door (CB302); and emergent maintenance of C main feedwater pump and C steam generator water level 7300 process card failure
b. Findings
No findings were identified.
1R15 Operability Evaluations
a. Inspection Scope
The inspectors reviewed four operability evaluations listed below, affecting risk significant mitigating systems to assess, as appropriate:
- (1) the technical adequacy of the evaluations;
- (2) whether operability was properly justified and the subject component or system remained available, such that no unrecognized increase in risk occurred;
- (3) whether other existing degraded conditions were considered;
- (4) that the licensee considered other degraded conditions and their impact on compensatory measures for the condition being evaluated; and,
- (5) the impact on TS limiting conditions for operations and the risk significance in accordance with the significance determination process. Also, the inspectors verified that the operability evaluations were performed in accordance with station administrative procedure (SAP)-209, Revision 0E, Operability Determination Process, and SAP-999, Revision 4C, Corrective Action Program.
- CR-10-01427, air supply regulator to MDEFW valve 1FV03541 drifted high causing relief valve to lift
- CR-10-01724, low electric hydraulic control fluid pressure main control board annunciator alarmed satisfying reactor trip logic
- CR-10-02202, C steam generator narrow range water level low and power supply failure annunciators alarmed
b. Findings
No findings were identified.
1R18 Plant Modifications
.1 Temporary Modification
a. Inspection Scope
For the equipment change listed below that was considered a temporary modification, the inspectors evaluated the changes for adverse effects on system availability, reliability, and functional capability. Documents reviewed, as applicable, included associated 10 CFR 50.59 reviews, engineering calculations, WOs and implementation packages, plant electrical and mechanical drawings, corrective action documents, applicable sections of the FSAR, supporting analyses, TS, and design basis information.
- Temporary instrument air system during demolition, removal, and replacement of the installed instrument/station air compressors and related equipment
b. Findings
No findings were identified.
.2 Permanent Modification
a. Inspection Scope
The inspectors reviewed a permanent modification associated with the upgrade of the instrument air and station air (IA/SA) system. The modification involved the replacement of the existing two centrifugal IA/SA air compressors, the IA dryer, the two IA pre-filters and after-filters, as well as the associated system controls. Two new oil free, rotary screw air compressors were being installed, along with two new parallel, heated desiccant dryer skids with integral pre and after filters. The intent of the upgrade was to provide more efficient, reliable air compressors with higher quality air to plant components. Documents reviewed included engineering change request (ECR)implementation procedures, modification design and implementation packages, WOs, site drawings, applicable sections of the FSAR, supporting 10 CFR 50.59 evaluations, TS, and design basis information. The inspectors witnessed aspects of the modification implementation and observed aspects of post-modification testing to verify adequate testing of the changes.
The inspectors evaluated the change documents and associated 10 CFR 50.59 reviews against the system design basis documentation and FSAR to verify that the changes did not adversely affect the safety function of safety systems.
The permanent modification and the associated attributes reviewed are as follows:
ECR 50538, Replacement of IA/SA Compressors and IA Dryer;
- Licensing Basis
- Failure Modes
- Energy Needs
- Control Signals
- Plant Document Updating
- Operations
- Flow paths
- Implementation
- Post Modification Testing
- Operability/Surveillance Testing The inspectors also reviewed selected CRs associated with the modification to confirm that problems were identified at an appropriate threshold, were entered into the CAP, and appropriate corrective actions had been initiated.
b. Findings
No findings were identified.
1R19 Post Maintenance Testing
a. Inspection Scope
For the six maintenance activities listed below, the inspectors reviewed the associated post-maintenance testing (PMT) procedures and either witnessed the testing and/or reviewed test records to assess whether:
- (1) the effect of testing on the plant had been adequately addressed by control room and/or engineering personnel;
- (2) testing was adequate for the maintenance performed;
- (3) test acceptance criteria were clear and adequately demonstrated operational readiness consistent with design and licensing basis documents;
- (4) test instrumentation had current calibrations, range, and accuracy consistent with the application;
- (5) tests were performed as written with applicable prerequisites satisfied;
- (6) jumpers installed or leads lifted were properly controlled;
- (7) test equipment was removed following testing; and,
- (8) equipment was returned to the status required to perform its safety function. The inspectors verified that these activities were performed in accordance with general test procedure (GTP)-214, Revision 5A, Post Maintenance Testing Guideline.
- WO 1005363, PMT for the emergent replacement of the B feedwater regulating valve digital valve controller primary feedback transducer
- WO 1005322, PMT for the C chiller failure of the hot gas bypass valve
- WO 1009003, PMT for the trip and card replacement of C main feed pump
b. Findings
No findings were identified.
1R22 Surveillance Testing
a. Inspection Scope
The inspectors observed and/or reviewed the five surveillance test procedures (STPs)listed below to verify that TS surveillance requirements were followed and that test acceptance criteria were properly specified to ensure that the equipment could perform its intended safety function. The inspectors verified that proper test conditions were established as specified in the procedures, that no equipment preconditioning activities occurred, and that acceptance criteria were met.
In-Service Tests:
- STP-205.004, Revision 7, RHR Pump and Valve Operability Test Reactor Coolant System Leakage Tests:
- STP-114.002, Revision 12A, Operational Leakage Calculation Other Surveillance Tests:
- STP-220-007, Revision 4C, Backup Air Supply Check Valve Test for Emergency Feedwater Valves
- STP-125.002A, Revision 1H, Diesel Generator A Operability Test
- STP-223.002A, Revision 9D, Service Water Pump Test
b. Findings
No findings were identified.
Cornerstone: Emergency Preparedness
1EP6 Drill Evaluation
a. Inspection Scope
On June 7, 2010, the inspectors reviewed and observed the performance of an emergency planning simulator drill that involved the loss of all AC electrical power and required a Site Area Emergency to be declared (LOR-SA-008). The inspectors assessed 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 critique performance. The inspectors verified that the drill critique identified drill performance weaknesses and addressed the issues appropriately.
b. Findings
No findings were identified.
OTHER ACTIVITIES
4OA1 Performance Indicator (PI) Verification
Cornerstone: Reactor Safety Barrier Integrity
a. Inspection Scope
The inspectors verified the accuracy of the licensees PI submittals listed below for the period April 2009 through March 2010. The inspectors used the performance indicator definitions and guidance contained in Nuclear Energy Institute (NEI) 99-02, Revision 6, Regulatory Assessment Performance Indicator Guideline, and licensee procedure SAP-1360, Revision 1, NRC and INPO/WANO Performance Indicators, to check the reporting of each data element. The inspectors sampled licensee event reports (LERs),operator logs, plant status reports, CRs, and performance indicator data sheets to verify that the licensee had properly reported the PI data. Also, the inspectors discussed the PI data with the licensee personnel associated with the performance indicator data collection and evaluation.
- Reactor Coolant System (RCS) Specific Activity
- RCS Identified Leak Rate
b. Findings
No findings were identified.
4OA2 Identification and Resolution of Problems
.1 Review of Items Entered into the Corrective Action Program
a. Inspection Scope
As required by Inspection Procedure 71152, Identification and Resolution of Problems, and in order to help identify repetitive equipment failures or specific human performance issues for follow-up, the inspectors performed a daily screening of items entered into the licensees CAP. This review was accomplished by either attending daily screening meetings that briefly discussed major CRs, or accessing the licensees computerized corrective action database and reviewing each CR that was initiated.
b. Findings
No findings were identified.
.2 Semi-Annual Review to Identify Trends
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 review was focused on repetitive equipment issues, but also considered trends in human performance errors, the results of daily inspector corrective action item screening discussed in Section 4OA2.1 above, licensee trending efforts, and licensee human performance results. The review nominally considered the six-month period of January 2010 through June 2010. Documents reviewed included licensee monthly and quarterly corrective action trend reports, engineering system health reports, maintenance rule documents, department self-assessment activities, and quality assurance audit reports.
b. Assessment and Observations No new adverse trends were identified for this period that had not already been identified by the licensee.
.3 Annual Sample Review
a. Inspection Scope
The inspectors reviewed the issue listed below in detail to evaluate the effectiveness of the licensees corrective actions for important safety issues.
- CR-09-04134, A SWBP breaker difficult to rack out The inspectors assessed whether the issues were identified; documented accurately and completely; properly classified and prioritized; adequately considered extent of condition, generic implications, common cause, and previous occurrences; adequately identified root causes/apparent causes; and identified appropriate corrective actions. Also, the inspectors verified the issues were processed in accordance with procedure SAP-999, Revision 4C, Corrective Action Program.
b. Findings and Observations
The inspectors identified two weaknesses with the licensee's evaluation and corrective actions with the CR reviewed. This CR documented the issue where the A SWBP breaker made a grinding noise and stopped moving in the outward direction during racking out operations. The inspectors performed a MR review of this CR and observed that the identified issue with the breakers racking mechanism did not receive a MRFF assessment as part of the condition evaluation. The causal evaluation weakness involved the licensees maintenance rule evaluation. Since one function of the racking mechanism is to secure the breaker in its cubicle during a seismic event, which thereby retains the breakers operability, the breaker should have received a MRFF evaluation based on the seismic aspect, and the sites MR implementation procedure should have included seismic considerations as one of its entry criteria. The corrective action weakness involved the lack of consideration for operator training. Since the racking mechanism issue was caused by operator poor practice, this CR should have addressed this training deficiency. The licensee documented these weaknesses in their CAP be re-opening CR-09-04134 and adding Actions #1 and #2.
4OA3 Event Followup
(Closed) Unresolved Item (URI)05000395/2009005-03, Control of Electrical Grounding Devices Resulting in Fires in the Turbine Building Non-Safety-Related Switchgear.
a. Inspection Scope
URI 05000395/2009005-03 was opened in NRC Integrated Inspection Report 05000395/2009005 during initial review of the November 22, 2009, UE that was declared for multiple fires in the protected area lasting greater than 15 minutes. The licensee determined that the cause of the fires was from the failure to remove grounding protection devices from the 7.2 kilovolt (kV) balance-of-plant (BOP) normal incoming breaker cubicles XSW1A, XSW1B, and XSW1C. The URI was opened pending the NRC staffs characterization of this issue following completion of the licensees root cause evaluation and subsequent NRC review. The licensees root cause analysis (RCA) report and supporting documents associated with the event were reviewed to assess the identified issues. The characterization of this issue as a finding and its risk significance are discussed below. This URI is closed.
b. Findings
Introduction:
A Green self-revealing non-cited violation (NCV) of TS 6.8.1.a was identified for the failure to establish adequate procedural tagging controls of safety and non-safety related electrical ground protection equipment which contributed to the main power transformer being energized while electrical ground protection equipment was still installed in three 7.2 kV BOP switchgear breaker cubicles. This condition resulted in a complete loss of BOP power due to the faults to ground, significant arc flashing, and subsequent fires in each of the three switchgear breaker cubicles requiring onsite and offsite fire brigade response and the declaration of an UE.
Description:
On October 17, 2009, during refueling outage 18, under tagging order addendum 09-111-3, personnel ground protection devices (i.e., test breaker ground carts) were installed in each of the three 7.2 kV BOP switchgear incoming breaker cubicles XSW1A, XSW1B, and XSW1C, to support the main transformer (XTF-1)replacement work. As part of this tagging order addendum, danger (red) tags were placed on each of the phase related ground straps that physically connected the line side of the transformer to the switchgear grounding system. On November 13, 2009, in accordance with tagging order addendum 09-111-38, the grounding straps were disconnected from the three test breaker ground carts in preparation for service testing of the unit auxiliary transformer (XTF-2). The red tags were removed from the ground straps at this time. The test breaker ground carts were not required to be removed and were left inside the cubicles in the racked in position. On November 16, 2009, an electrician reinstalled the grounding straps to the three test breaker ground carts in support of substation personnel who were continuing outage related service testing associated with XTF-2. However, no red tags were requested from operations to be installed on the grounding straps. On November 22, 2009, XTF-1 was initially energized as part of the post-modification test procedure (MTP-50495). This energized XTF-2 without having removed the ground straps or racked out the test ground breakers in the three 7.2 kV BOP normal incoming switchgear breaker cubicles. As a result of this configuration error, a direct path to ground was created causing significant arc flashing and subsequent fires in each of the three 7.2 kV BOP normal incoming breaker cubicles.
The licensees root cause investigation was documented in RCA 09-05093. The licensee identified several causal factors for the incident. The main causal factor involved the failure to install red tags on the grounding straps when the straps were re-installed by the electrician on November 16, 2009. The root cause for this was attributed to the electricians failure to follow established industrial safety procedure requirements and electrical shop policy expectations for utilizing the station tagout procedure (i.e.,
SAP-201, Equipment Tagging and Lockout-Tagout) for red tagging the installation of protective ground equipment. However, the RCA recognized that SAP-201 failed to specifically require the hanging of red tags when installing ground protection equipment.
The RCA also identified, as a contributing factor, a precursor event that occurred in May 2005 involving the discovery of a ground protection device on the A phase of the main generator breaker while performing meggar testing. The apparent cause associated with this previous event recommended that a program for tracking installed grounds be developed. However, the actual action taken resulted in verbally communicating a policy change that all grounds for generator work would be installed under SAP-201 red tagging, but the procedure was not formally revised to make this a requirement.
The inspectors reviewed the licensees RCA and agreed with the licensees conclusion that the cause of the event was the failure to properly control the configuration of ground protection equipment via the station equipment tagout procedure. The licensees immediate corrective actions included revision of SAP-201 to require red tags to be hung associated with the installation of ground protection equipment. Other significant planned corrective actions included: 1) revising station and department administrative procedures for energizing equipment greater than 600 volts to require a physical walkdown/verification that grounding devices have been removed prior to energizing equipment, 2) revising all maintenance procedures requiring grounding of circuits greater than 480 volts to require red tags to be hung with the installation of ground devices, and 3) conducting training for all operations and electrical maintenance personnel on the installation of grounding devices and the revised tagging requirements.
Analysis:
The inspectors determined that the licensees failure to develop an adequate station tagout procedure for controlling the configuration of safety and non-safety related ground protection equipment was a performance deficiency that was within the licensees ability to foresee and correct. While this event involved the mis-configuration of ground protection in non-safety-related BOP switchgear, the same station tagout procedural requirements apply to the control of safety-related equipment. This finding is more than minor because the failure to properly control the configuration of safety and non-safety related ground protection electrical equipment, if left uncorrected, would have the potential to lead to a more significant safety concern. In addition, the finding is associated with the protection against external factors attribute of the initiating events cornerstone and affected the cornerstone objective to limit the likelihood of events that upset plant stability and challenge critical safety functions during shutdown, in that, the failure to properly control the configuration of the ground protection equipment resulted in fires in three switchgear cubicles requiring onsite and offsite fire brigade response actions and the declaration of an UE. Since this problem occurred while the station was in cold shutdown (Mode 5) with the pressurizer solid and all three reactor coolant pumps initially bumped, NRC Inspection Manual Chapter (IMC) 0609, Significance Determination Process, Appendix G, Shutdown Operations Significance Determination Process, was used to assess the significance of this finding. Using Phase 1 of Appendix G, the finding was determined to be of very low significance (Green) because it did not result in an actual loss of offsite power event nor degrade the licensees ability to cope with such an event since both emergency diesel generators remained available, as well as, the dedicated offsite AC and alternate power sources. This finding involved the cross-cutting area of human performance, the component of resources, and the aspect of complete, accurate and up-to-date procedures, H.2(c), because the licensee failed to establish adequate station tagout procedures for controlling the installation and removal of safety and non-safety related ground protection equipment.
Enforcement:
TS 6.8.1.a, Procedures and Programs, requires that written procedures be established, implemented, and maintained covering the activities specified in Appendix A, Typical Procedures for Pressurized Water Reactors, of Regulatory Guide 1.33, Quality Assurance Program Requirements, Revision 2, February 1978.
Regulatory Guide 1.33, Appendix A, section 1.c, requires administrative procedures for equipment control (e.g., equipment locking and tagging). Station administrative procedure SAP-201, Revision 10B, Equipment Tagging and Lockout-Tagout, provided the requirements for controlling the configuration of equipment under the station tagout program. Contrary to the above, on November 22, 2009, the licensee failed to establish and maintain adequate procedural guidance for controlling ground protection equipment under the tagout program for both safety-related and non-safety-related electrical equipment. This procedural inadequacy contributed to ground protection equipment being left in three 7.2 kV BOP switchgear breaker cubicles when the switchgear was energized resulting in a complete loss of BOP power due to the faults to ground, fires in the three switchgear cubicles requiring onsite and offsite fire brigade response, and the declaration of an UE. Because this finding is of very low safety significance and has been entered into the licensees corrective action program as CR-09-05093, this violation is being treated as an NCV, consistent with Section IV.A.1 of the NRC Enforcement Policy: NCV 05000395/2010003-01, Inadequate Station Tagout Procedure for Controlling Safety and Non-safety Related Grounding Equipment Results in Loss of All Balance of Plant Power and Switchgear Fires.
4OA5 Other Activities
Quarterly Resident Inspector Observations of Security Personnel and Activities
a. Inspection Scope
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
Exit Meeting Summary
On July 20, 2010, the inspectors presented the integrated inspection results to Mr.
Thomas Gatlin and other members of the licensee staff. The licensee acknowledged the results of these inspections. The inspectors confirmed that inspection activities discussed in this report did not contain proprietary material.
ATTACHMENT:
SUPPLEMENTAL INFORMATION
KEY POINTS OF CONTACT
Licensee Personnel
- J. Archie, Senior Vice President, Nuclear Operations
- A. Barbee, Director, Nuclear Training
- L. Bennett, Manager, Plant Support Engineering
- L. Blue, Manager, Nuclear Training
- M. Browne, Manager, Quality Systems
- M. Coleman, Manager, Health Physics and Safety Services
- G. Douglass, Manager, Nuclear Protection Services
- M. Fowlkes, General Manager, Engineering Services
- D. Gatlin, Vice President, Nuclear Operations
- R. Haselden, General Manager, Organizational / Development Effectiveness
- R. Justice, Manager, Nuclear Operations
- G. Lippard, General Manager, Nuclear Plant Operations
- M. Mosley, Manager, Chemistry Services
- J. Nesbitt, Manager, Materials and Procurement
- D. Shue, Manager, Maintenance Services
- W. Stuart, Manager, Design Engineering
- B. Thompson, Manager, Nuclear Licensing
- R. Williamson, Manager, Emergency Planning
- S. Zarandi, General Manager, Nuclear Support Services
LIST OF ITEMS OPENED, CLOSED, AND DISCUSSED
Opened and Closed
- 05000395/2010003-01 NCV Inadequate Station Tagout Procedure for Controlling Safety and Non-safety Related Grounding Equipment Results in Loss of All Balance of Plant Power and Switchgear Fires (Section 4OA3)
Closed
- 05000395/2009005-03 URI Control of Electrical Grounding Devices Resulting in Fires in the Turbine Building Non-Safety-Related Switchgear (Section 4OA3)