IR 05000237/2012007
| ML12144A420 | |
| Person / Time | |
|---|---|
| Site: | Dresden  |
| Issue date: | 05/23/2012 |
| From: | Jamnes Cameron NRC/RGN-III/DRP/B6 |
| To: | Pacilio M Exelon Generation Co, Exelon Nuclear |
| References | |
| IR-12-007 | |
| Download: ML12144A420 (32) | |
Text
May 23, 2012
SUBJECT:
DRESDEN NUCLEAR POWER STATION, UNITS 2 AND 3 PROBLEM IDENTIFICATION AND RESOLUTION INSPECTION REPORT 05000237/2012007; 05000249/2012007
Dear Mr. Pacilio:
On April 20, 2012, the U.S. Nuclear Regulatory Commission (NRC) completed an inspection at your Dresden Nuclear Power Station, Units 2 and 3. The enclosed report documents the results of this inspection, which were discussed on April 26, 2012, with Mr. D. Czufin, and other members of your staff.
This inspection was an examination of activities conducted under your license as they relate to problem identification and resolution and compliance with the Commissions rules and regulations and the conditions of your license. Within these areas, the inspection involved examination of selected procedures and representative records, observations of activities, and interviews with personnel.
Based on the inspection sample, the inspection team concluded that the implementation of the corrective action program and overall performance related to identifying, evaluating, and resolving problems at Dresden was adequate. Licensee identified problems were entered into the corrective action program at a low threshold. Problems were generally prioritized and evaluated commensurate with the safety significance of the problems. Corrective actions were generally implemented in a timely manner commensurate with their importance to safety and addressed the identified causes of problems. Lessons learned from industry operating experience were effectively reviewed and applied when appropriate. Audits and self-assessments were effectively used to identified problems and appropriate actions.
Based on the results of this inspection, one NRC-identified finding of very low safety significance was identified. The finding involved a violation of NRC requirements. However, because of the very low safety significance, and because the issue was entered into your corrective action program, the NRC is treating the issue as a Non-Cited Violation (NCV) in accordance with Section 2.3.2 of the NRC Enforcement Policy. If you contest the subject or severity of this NCV, you should provide a response within 30 days of the date of this inspection report, with the basis for your denial, to the U.S. Nuclear Regulatory Commission, ATTN: Document Control Desk, Washington, DC 20555-0001, with a copy to the Regional Administrator, U.S. Nuclear Regulatory Commission - Region III, 2443 Warrenville Road, Suite 210, Lisle, IL 60532-4352; the Director, Office of Enforcement, U.S. Nuclear Regulatory Commission, Washington, DC 20555-0001; and the Resident Inspector Office at the Dresden Nuclear Power 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, Region III, and the NRC Resident Inspector at the Dresden Nuclear Power Station.
In accordance with 10 CFR 2.390 of the NRC's "Rules of Practice," a copy of this letter, its enclosure, and your response (if any) will be available electronically for public inspection in the NRC Public Document Room or from the Publicly Available Records System (PARS)
component of NRC's document 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 John E. Rutkowski for/
Jamnes L. Cameron, Chief
Branch 6
Division of Reactor Projects
Docket Nos. 50-237 and 50-249 License Nos. DPR-19 and DPR-25
Enclosure:
Inspection Report 05000237/2012007; 05000249/2012007 w/Attachment: Supplemental Information
REGION III==
Docket Nos:
05000237; 05000249 License Nos:
05000237/2012007; 05000249/2012007 Licensee:
Exelon Generation Company, LLC Facility:
Dresden Nuclear Power Station, Units 2 and 3 Location:
Morris, IL Dates:
April 2 through 20, 2012 Inspectors:
R. Orlikowski, Project Engineer (Team Lead)
Z. Falevits, Senior Reactor Inspector
V. Meghani, Reactor Inspector
T. Briley, Resident Inspector (acting)
H. Freeman, Senior Reactor Inspector Approved by:
J. Cameron, Chief
Branch 6
Division of Reactor Projects
Enclosure
SUMMARY OF FINDINGS
Inspection Report (IR) 05000237/2012007; 05000249/2012007; [04/02/2012 - 04/20/2012];
Dresden Nuclear Power Station, Units 2 & 3; Problem Identification and Resolution (PI&R).
This inspection was performed by four NRC regional inspectors and the resident inspector.
One Green finding was identified by the inspectors. The finding was considered a Non-Cited Violation (NCV) of NRC regulations. The significance of most findings is indicated by their color (Green, White, Yellow, Red) using Inspection Manual Chapter (IMC) 0609, Significance Determination Process (SDP). 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.
Based on the inspection sample, the inspection team concluded that the implementation of the corrective action program and overall performance related to identifying, evaluating, and resolving problems at Dresden was adequate. Licensee identified problems were entered into the corrective action program at a low threshold. Problems were generally prioritized and evaluated commensurate with the safety significance of the problems. Corrective actions were generally implemented in a timely manner commensurate with their importance to safety and addressed the identified causes of problems. Lessons learned from industry operating experience were effectively reviewed and applied when appropriate. Audits and self-assessments were effectively used to identified problems and appropriate actions. On the basis of interviews conducted during the inspection, workers at the site expressed freedom to enter safety concerns into the Corrective Action Program.
Problem Identification and Resolution There was one Green finding identified by the team during the inspection. The finding related to identification and removal of corrosion from the 2/3 Diesel Fire Pump battery terminals and was similar to a finding identified during a 2011 Fire Protection inspection at Dresden. The finding had a cross-cutting aspect in the area of PI&R.
A.
Cornerstone: Mitigating Systems
NRC-Identified
and Self-Revealed Findings
- Green
. The inspectors identified a finding of very low safety significance (Green) and associated NCV of Technical Specifications for the licensees failure to adequately implement the diesel fire pump (DFP) battery surveillance procedure. Specifically, the licensee failed to identify and remove corrosion on the DFP battery terminals, which was contrary to the surveillance procedure that implemented the fire protection program. A similar NCV was previously cited by the NRC on October 17, 2011, and documented in inspection report 05000237/2011008; 05000249/2011008, Failure to Identify Diesel Fire Pump Battery Terminal Corrosion. The licensee entered the issue into their corrective action program and planned to clean the battery terminals. In addition, the licensee planned to replace the 2/3 DFP batteries in July 2012.
The inspectors determined that the finding was more than minor because, if left uncorrected, the presence of corrosion in conjunction with identified voltage issues for two battery cells could affect the reliability of the diesel fire pump. This finding was of very low safety significance because the DFP had started as part of a recent routine surveillance. This finding has a cross-cutting aspect in the area of PI&R because the licensee failed to identify the battery corrosion accurately and in a timely manner commensurate with their safety significance. [IMC 0310 P.1(a) (Section 4OA2.1.B(3))
B.
No violations were identified.
Licensee-Identified Violations
REPORT DETAILS
OTHER ACTIVITIES
4OA2 Problem Identification and Resolution
The activities documented in Sections
.1 through.4 constituted one biennial sample of
problem identification and resolution as defined in Inspection Procedure (IP) 71152.
(71152B)
.1 a.
Assessment of the Corrective Action Program Effectiveness The inspector reviewed the licensees Corrective Action Program (CAP) implementing procedures and attended CA program meetings to assess the implementation of the CAP by site personnel.
Inspection Scope The inspectors reviewed risk and safety significant issues in the licensees CAP since the last NRC Problem Identification and Resolution (PI&R) inspection in March 2010.
The selection of issues ensured an adequate review of issues across NRC cornerstones. The inspectors used issues identified through NRC generic communications, department self assessment, licensee audits, operating experience reports, and NRC documented findings as sources to select issues. Additionally, the inspectors reviewed issue reports generated as a result of facility personnels performance in daily plant activities. In addition, the inspectors reviewed Issue Reports (IRs) and a selection of completed investigations from the licensees various investigation methods, which included root cause, apparent cause, equipment apparent cause, common cause, and quick human performance investigations.
The inspectors selected the Low Pressure Coolant Injection (LPCI) system for a detailed review. The inspectors review was to determine whether the licensee staff were properly monitoring and evaluating the performance of the system through effective implementation of station monitoring programs. A 5 year review was performed to assess the licensee staffs efforts in monitoring for system degradation due to aging aspects. The inspectors also performed partial system walkdowns of the LPCI system.
During the reviews, the inspectors determined whether the licensee staffs actions were in compliance with the facilitys corrective action program and 10 CFR 50, Appendix B, requirements. Specifically, the inspectors determined if licensee personnel were identifying plant issues at the proper threshold, entering the plant issues into the stations CAP in a timely manner, and assigning the appropriate prioritization for resolution of the issues. The inspectors also determined whether the licensee staff assigned the appropriate investigation method to ensure the proper determination of root, apparent, and contributing causes. The inspectors also evaluated the timeliness and effectiveness of corrective actions for selected issue reports, completed investigations, and NRC findings, including Non-Cited Violations (NCVs).
b.
- (1) Assessment Issues were generally being identified at a low threshold, evaluated appropriately, and corrected in the CAP. Workers were familiar with the CAP and felt comfortable raising concerns. This was evident by the large number of CAP items generated annually; which were reasonably distributed across the various departments. A shared, computerized database was used for creating individual reports and for subsequent management of the processes of issue evaluation and response. These processes included determining the issues significance, addressing such matters as regulatory compliance and reporting, and assigning any actions deemed necessary or appropriate.
Effectiveness of Problem Identification The inspectors determined that the station was generally effective at trending low level issues to prevent larger issues from developing. The licensee also used the CAP to document instances where previous CAs were ineffective or were inappropriately closed.
Observations The inspectors determined that Nuclear Oversight (NOS) personnel were identifying plant issues at the proper threshold, entering the plant issues into the stations CAP in a timely manner. However, the licensee extended a number of times the originally assigned due dates for resolution of several issues. For example, on January 10, 2012, NOS issued Escalation letter #12-01 citing Dresdens Electrical Maintenance Group for ineffective implementation of the In-Storage Maintenance (ISM) process. The Electrical Maintenance Group initiated followup corrective actions to address the NOS findings.
Also, Common Cause Analysis (CCA) 01254964 was initiated by NOS on February 24, 2012, to document an adverse trend in Preventive Maintenance (PM) not being properly identified resulting in equipment reliability challenges.
Nuclear Oversight No findings were identified.
Findings
- (2) The inspectors concluded that the station was generally effective at prioritizing issues commensurate with their safety significance. The inspectors observed that the majority of issues identified were of low-level and were either closed to trend, closed to actions taken, or characterized at a level appropriate for a condition evaluation. Issues were being appropriately screened by both the Station Oversight Committee (SOC) and Management Review Committee (MRC). There were no items in the operations, engineering, or maintenance backlogs that were risk-significant, individually or collectively. The inspectors did identify deficiencies in Dresden Nuclear Power Stations prioritization and evaluation of several issues.
Effectiveness of Prioritization and Evaluation of Issues Observations The inspectors reviewed corrective actions generated to address critical R20 type HFA relays and other relay PM deficiencies as documented in numerous IRs, Equipment Apparent Cause Evaluations (EACEs) and CCAs. The team noted that numerous IRs have been issued that documented problems with ensuring that all plant installed critical safety-related (SR) HFA and other manufacturer relays have assigned PM tasks to periodically replace the critical relays. This periodic replacement was required by the licensees Predictive Centered Maintenance (PCM) Template and applicable vendor recommendations.
Preventive Maintenance Deficiencies Related to Lack of Periodic Replacement of Aging Critical HFA and Agastat Relays The inspectors reviewed the following cause evaluations performed to identify the apparent and contributing cause(s) of component failures associated with installed HFA and Agastat relays (some classified as critical, normally energized).
- EACE 1242095-03; GE [General Electric] HFA Relay Failure Results in the Inability to Start the 3A RFP [Reactor Feed Pump];
- EACE1136770-02; 3A Core Spray Pump Fails to Start within Acceptance Criteria. (Due to failure of the electronic Agastat (Tyco ETR and FTR series)pump start relay and resistive control switch contacts).
The inspectors also reviewed CCA 01254964, initiated by NOS on August 24, 2011, to document an adverse trend in PM not being properly identified resulting in equipment reliability challenges. NOS recommended a CCA be performed for Dresden EACEs completed between August 2009 and August 2011. The CCA concluded that relay failures evaluated in the EACEs reviewed were one of two top contributors of common failure issues with 13 out of 69 items or 19 percent of total failures.
The following are examples of IRs issued to document equipment problems caused by relay failures due to high relay contact resistance:
- IR 973104, 3A RWCU Pump Tripped; and
- IR 1026125, Bus 29 Cubicle 3B Breaker Failed to Close following Electrical Maintenance Department (EMD) PM.
The following are examples of IRs issued to document equipment problems caused by relay failures due to deficient PMs:
- IR 1076914, 2A RWCU Recirc. Pump Trip-Unit 2 (HFA relay had bad coil);
- IR 1242095, No Standby Light for 3A RFP When in Standby; and
- IR 1123492, HCCT 1A Pump Relay Appears to be Defective.
The following are examples of IRs issued to document equipment problems caused by deficient PMs:
- IR 1079909, Loss of U3 ESS Normal AC/DC;
- IR 1218276, Unexpected U3 Half SCRAM Due to 3B RBS Bus Trip; and
- IR 1226454, U2 SBO UPS Inverter Failed.
IR 1254964-13 was generated on September 8, 2011, to document deficient relay PMs on System 73 (480VAC Transformer/SWGR) and on System 78 (480V MCC). The licensees review identified that 10 year replacement was not established as required by the PCM Template for relays classified as SR critical 3 category relays and that no PMs were performed on under voltage relays located at Bus 38. IR 01329930 and SR 76377 were initiated on February 24, 2012, to address these PM deficiencies.
The inspectors noted that NRC finding FIN 05000237/2011004-03; 05000249/2011004-03, Inadequate Relay Preventive Maintenance, was issued for inadequate PMs on the failed HFA relay. The failure of the HFA relay resulted in the inability to start the 3A reactor feed pump.
In addition, IR 1136770 was issued on November 11, 2010, to document that, 3A Core Spray Pump Fails to Start within Acceptance Criteria. The failure was attributed to failure of the electronic Agastat (now called Tyco ETR and FTR relay series) pump start relay and resistive control switch contacts. EACE 1136770-02 identified the most likely cause for the relay failure was the lack of PM to periodically replace the Agastat relay.
Manufacturer qualified life of this relay is 10 years, and the manufacturer recommends replacement every 10 years based on Institute of Electrical and Electronic Engineers (IEEE) qualifications. Also, the most likely identified cause for the high resistance of the switch contact was lack of PM to periodically burnish the contacts or replace the switch.
The Licensees extent of cause review stated that there are other Agastat electronic time delay relays (TDRs) installed at Dresden and that a CA was created to review and address this issue. An action for Plant Engineering Group Supervisors was recommended to assign each system manager actions to review their systems for TYCO ETR and FTR series TDRs and issue a Service Request to create PMs for replacement of the critical relays on the appropriate time frequency. This CAP item had been extended four times since January 2011 and the last specified due date was June 29, 2012.
The inspectors were informed that the licensee planned to review the following systems, to identify category 3 HFA and Agastat relays and determine which relays needed periodic replacements: Heating Ventilation and Air-conditioning (HVAC), Station Blackout (SBO), and Standby Gas Treatment (SBGT). A number of relay replacement due dates had been extended for replacement of the relays.
The inspectors noted that a number of Action Tracking Items (ATIs) were initiated to review all relays within U2 and U3 systems logic to determine which relays were critical and if they have periodic replacement PMs. For example, ATI 1076914-19 was issued to review all critical normally energized relays in LPCI logic. The review identified that not all critical relays had the required periodic replacement PMs assigned. The licensee identified that six critical relays in each Unit were not correctly classified as critical and therefore did not have periodic replacements PMs. SR 70086 was initiated to generate the required PMs and to replace these relays during the next few outages in Units 2 and
3. Other ATIs were generated for other systems being evaluated. This effort had been
going on since about 2002.
In response to the inspectors question, the licensee performed an initial review of the standby gas treatment system and identified that this system had 30 HFA relays of which eight were normally energized and are believed to be greater than 10 years old. A licensee review of work history showed that these eight energized relays have not been replaced in the past and no documentation could be located by the licensee to indicate that these relays had failed in the past.
The inspectors questioned the licensee regarding the operability of plant installed critical HFA, Agastat and other types of important to safety relays that were past their qualified life of 10 years. The licensee stated that these relays are periodically tested by performance of Logic Functional Surveillance Testing at which time it is checked that the relays pick up and drop out as required.
The inspectors noted that there was no owner responsible for coordinating the critical relays, electrolytic capacitors, and other important to safety components review effort to ensure that all components with deficient PM replacement periods have been identified and addressed (implemented in the field). This is required to comply with Exelons PCM template and vendor requirements.
The team identified a potential decline in operations sensitivity to spurious or repeat control alarms and dispatching non-licensed operators in a timely manner. The team reviewed licensee corrective actions to NRC finding 05000237/2011002-07; 05000249/2011002-07, which was a finding of very low safety significance (Green) for bypassing the 3B Circulating Water Pump lower bearing temperature computer alarm without first verifying the instrument reading. The 3B Circulating Water Pump lower bearing subsequently failed due to low oil level.
Operator Sensitivity to Spurious or Repeat Control Room Alarms An EACE for the 3B Circulating Water Pump lower bearing failure, documented in IR 1159133, Secured 3B Pump due to Oil Loss, developed three lessons learned:
1) When alarms are received that have been spurious in the past do not assume the current alarm is also spurious. 2) During times when control room activities require focused attention, do not delay dispatching operators to the field any longer than necessary to check off-normal equipment conditions. 3) When receiving a turnover that includes information regarding possible equipment conditions, do not delay follow-up including dispatching operators to perform field checks.
One of the corrective actions as a result of NRC finding 2011002-07 included distributing a communication to all operators with the 3B Circulating Water Pump lower bearing failure lessons learned. The team questioned the lasting effects of the lessons learned communicated to the operators, in particular having a high sensitivity to alarms coming in that may or may not be spurious and the timeliness of dispatching non-licensed operators to the field. The team noted several examples of operators not exhibiting the expected behaviors with regard to alarm response. Most recently, in February 2012 the licensee failed to respond in a timely manner to a computer alarm warning that the average power range monitors (APRM) gain adjustment factor settings were not within limits during a Unit 2 downpower resulting in APRM 4, 5, and 6 being inoperable simultaneously. The Nuclear Station Operator, the Unit Supervisor, the Reactivity Manager, and the Qualified Nuclear Engineer were all aware that the alarm had sounded but no action was taken to verify the extent of or correct the problem until after the next shift took over. This issue was documented in NRC Integrated Inspection Report 2012002 as FIN 05000237/2012002-09.
The team also noted that the Safety Parameter Display System (SPDS) computer alarm indicator was constantly flashing for Unit 2 in the main control room. When questioned, one of the unit supervisors did not know the purpose of the alarm or why it was flashing, indicating that it had always been there. Additional operator interviews indicated that the SPDS computer alarm was flashing because a computer point was in a constant alarm state. This issue was determined to be minor because a separate annunciator panel would provide a horn and light for any new computer alarm that may occur.
Future licensee corrective actions to the potential decline in operations sensitivity to spurious or repeat control alarms and dispatching non-licensed operators in a timely manner include, but are not limited to, incorporating enhanced focus on alarm response standards and expectations during operator training.
The inspectors found that, for the IRs reviewed, the licensee did not consistently evaluate the degraded condition or the operability of the component. Some of the operability evaluations provided objective evidence why a potentially degraded condition was deemed operable while other evaluations merely indicated that the component passes its last surveillance test and was therefore operable.
Review of Issue Reports Associated With Degraded Grease Identified In Motor Operator Valves and Condition Reports Associated With Degraded Magnesium Rotors For example, IR 01143050, which documented an evaluation of degraded grease (Grade 4) in MOV 3-2301-5. It provided objective evidence that while the color of the grease had turned dark brown with a hint of purple, the grease became soft and slippery when pressed between the fingers, there was no evidence of wear particles or burnt smell present, and the grease properly covered the gears. Based upon the appearance of the grease and diagnostic testing performed in refueling outage D3R21, the evaluation concluded that the motor operator would be operable for another operating cycle. The team concluded that this evaluation was appropriate for the identified condition.
However, IR 01279882 documented an evaluation of degraded grease (also Grade 4) in MOV 2-0205-24. The issue report stated that during performance of the diagnostic test
... the as-found stem lube was graded as a 4. The as-found thrust was lower than expected due to the poor stem lube. This indicates a degraded condition of the performance of the valve operator. The evaluation stated that MOV 2-0205-24 passed all surveillances, including quarterly valve timing and remained operable. The team concluded that this evaluation was not based upon objective evidence to predict future operability.
Additionally, IR 01289045 documented minor galvanic corrosion at the interface of the magnesium end ring and end lamination of the rotor in MOV 2-1201-1. The operable basis stated that the 2-1201-1 valve is required to close within 45 seconds to perform its active safety function, during a LOCA. This valve does not have a safety-related requirement to open. This valve was successfully stroked during D2R22. The evaluation did not provide any reference as to whether the stroke time had changed from previous surveillance tests. Once again, the inspectors concluded that this evaluation was not based upon objective evidence to predict future operability until the next refueling outage.
No findings were identified.
Findings
- (1) The effectiveness of corrective actions for the items reviewed by the inspectors was generally appropriate for the identified issues. Over the 2 year period encompassed by the inspection, the inspectors identified no significant examples where problems recurred. While no significant examples were identified, the inspectors did identify an observation regarding the timeliness of work order completion related to the LPCI system. Additionally, during review of the effectiveness of licensee corrective actions to address a previously identified NRC finding documented in inspection report as NCV 2011008-02, the team identified that the actions taken by the licensee did not prevent recurrence.
Effectiveness of Corrective Actions Observations One of the challenges identified through LPCI system health reports was the deficient maintenance work orders older than 24 months. During the review of sample issue reports, the inspectors also noted the following instances of assignments or work requests open for a long time that could all be indicative of a weakness in planning, funding, or resources. All of these examples were determined to be minor and did not rise to the level of an NRC finding.
Untimely Completion of Assignments/Work Requests
- AR 01055863-02: The corrective action was to revise the Emergency Core Cooling System (ECCS) corner room heating calculations related to an NCV documented in 2010003 NRC inspection report. The assignment due date has been revised six times and it appears that it will be revised due to lack of resources. The original due date was May 13, 2010, and the current due date is June 30, 2012. The reasons for the delays cited were lack of funding, emerging work and other priorities.
- AR 01074868: Main control room received 903-3 panel alarm for LPCI pump overload with no pumps in operation. Work Request (WR) 337790 was generated to perform the necessary repair in June 2010. Because the alarm cleared and has not occurred again, the WR has not been completed but remains open.
- AR 01062334-02: LPCI 3-1501-38A valve moved without operator input - a complex trouble shooting plan was developed with recommendation to perform specific steps in June 2010 during the quarterly ISTs. No action has been taken yet and the problem has not recurred.
Findings Failure to Identify and Remove Unit 2/3 Diesel Fire Pump Battery Terminal Corrosion
Introduction:
The inspectors identified a finding of very low safety significance (Green)and associated NCV of Technical Specifications for the licensees failure to implement the diesel fire pump battery surveillance procedure. Specifically, the licensee failed to identify visual corrosion on the Unit 2/3 diesel fire pump (DFP) battery terminals. This was contrary to the DFP and security diesel starting batteries surveillance and procedure requirements.
Description IR 0135220, dated April 10, 2012, documented and evaluated the corrosion on the 2/3 DFP battery terminals identified by the NRC, and that a loose connection on the positive post of cell #21was identified by the licensee during this followup inspection of the battery terminals. A work request was generated to tighten the loose connection.
The inspectors were also informed that the previously identified voltage issues on two of the battery cells would be corrected when the batteries are scheduled to be replaced in July 2012.
- During review of the licensees corrective actions to address issues identified by the NRC and documented as an NCV, the inspectors reviewed completed CA Assignment #10 of AR 01283859, dated January 20, 2012, which was performed to address NCV 05000237/2011008-02; 05000249/2011008-02, Failure to Identify Diesel Fire Pump Battery Terminal Corrosion. Specifically, on April 3, 2012, the inspectors performed a field walk down of the Unit 2/3 DFP battery and identified corrosion on at least six battery cell terminals and inter-cell electrical connections (i.e. #2, 4, 11, 23, 25
& 29) of the Unit 2/3 diesel fire pump battery. The inspectors were aware that terminal post corrosion was previously identified on these battery terminals and is a common problem for aging batteries. Corroded inter-cell connections and post connectors can fail when exposed to the design basis discharge current.
The inspectors noted that the DFP monthly surveillance was last performed on March 21, 2012, and the last quarterly surveillance was performed on February 22, 2012, under work order (WO) 01438993-01, D2/3 QTR TSTR [Technical Specification Technical Requirements] Diesel Fire PP [pump] Batt. Surv. and Procedure DES 8300-13, Unit 1 and 2/3 Diesel Fire Pump and Security Diesel Starting Batteries Surveillance and Manual Procedure, Revision 18. Step I.15.c of Procedure DES 8300-13 required that the battery be inspected for signs of corrosion and be cleaned as required. The inspectors reviewed the completed work order package and determined that although corrosion was present, step I.15.c had been marked as having been completed with no deficiencies noted.
The inspectors noted that as part of licensees corrective action to address the finding in NCV 05000237/2011008-02; 05000249/2011008-02, on November 30, 2011, the licensee thoroughly cleaned the battery terminals and removed the existing corrosion using WO 1476504-01. An electrical shop briefing was held and maintenance procedure DES-8300-13, was revised to state, if corrosion is found on battery post and cannot be cleaned due to inaccessibility notify Supervisor and document in IR. However, during interviews of maintenance personnel, the inspectors noted that the EMD technicians who performed the battery surveillances had not yet received sufficient training on how to recognize the presence of corrosion. The formal training had been scheduled for later this year. The inspectors also noted that the maintenance procedure was not revised to include specific guidance on how to identify different types of corrosion (i.e. white, brown, or green in color).
Based on the amount of corrosion identified by the inspectors during this inspection, and interviews with electrical personnel, the inspectors concluded that maintenance personnel had not properly completed Step I.15.c of Procedure DES 8300-13 because they failed to recognize the existing corrosion.
On April 10, 2012, the licensee initiated IR 01352200, 2/3 Diesel Fire Pump Battery Corrosion, to evaluate the condition of the cell terminals on the battery. The licensee subsequently informed the inspectors that the batteries are scheduled to be replaced in July 2012.
Analysis The inspectors determined that the finding was more than minor because, if left uncorrected, the presence of corrosion in conjunction with identified voltage issues for two battery cells could affect the reliability of the diesel fire pump. Specifically, the diesel fire pump battery surveillance procedure specified that the battery terminals were to be inspected for signs of corrosion and be cleaned as required. If left uncorrected, the presence of corrosion in conjunction with the identified voltage issues for two battery cells and the loose connection on cell #21 could affect the reliability of the diesel fire pump.
- The inspectors determined that the licensees failure to implement the DFP battery surveillance procedure was contrary to Technical Specifications and was a performance deficiency. Specifically, the licensees failure to identify corrosion on the diesel fire pump battery terminals was contrary to surveillance procedure DES 8300-13, a surveillance procedure for implementing the fire protection program.
In accordance with Inspection Manual Chapter (IMC) 0609, Significance Determination Process, Attachment 0609.04, Phase I - Initial Screening and Characterization of Findings, Table 3b, the inspectors determined the finding degraded the fire protection defense-in-depth strategies. Therefore, screening under IMC 0609, Appendix F, Fire Protection Significance Determination Process, was required.
The inspectors determined that the finding represented a low degradation because the diesel fire pump had successfully started as part of a routine surveillance performed during the last Quarterly Surveillance on February 22, 2012. Therefore, the inspectors determined that the finding screened as having very low safety significance (Green) in Task 1.3.1 of IMC 0609, Appendix F.
This finding has a cross-cutting aspect in the area of Problem Identification and Resolution, because the licensee failed to identify the battery corrosion accurately and in a timely manner commensurate with their safety significance. P.1(a)
Enforcement:
Technical Specification 5.4.1.c requires, in part, that written procedures be established, implemented, and maintained covering activities related to fire protection program implementation. Procedure DES 8300-13, Unit 1 and 2/3 Diesel Fire Pump and Security Diesel Starting Batteries Surveillance and Manual Procedure, Revision 18, was a procedure which implemented the fire protection program. Step I.15.c of Procedure DES 8300-13 required that the battery terminals be inspected for signs of corrosion and cleaned as required.
Contrary to the above, on April 3, 2012, the licensee failed to implement Procedure DES 8300-13. Specifically, the licensee had credited Step I.15.c of Procedure DES 8300-13 as having been completed on March 21, 2012, as part of the last monthly surveillance performed on the 2/3 diesel fire pump. However, the inspectors identified corrosion on the battery terminals for the 2/3 diesel fire pump on April 3, 2012, which had indicated that Step I.15.c of Procedure 8300-13 had not been properly implemented.
Because this violation was of very low safety significance and it was entered into the licensees CAP as IR 01349878 and IR 01352200, this violation is being treated as an NCV, consistent with Section 2.3.2 of the NRC Enforcement Policy (NCV 05000237/2012007-01; 05000249/2012007-01, Failure to Identify and Remove Diesel Fire Pump Battery Terminal Corrosion).
.2 a.
Assessment of the Use of Operating Experience The inspectors reviewed the licensees implementation of the facilitys Operating Experience (OE) program. Specifically, the inspectors reviewed implementing OE program procedures, attended CAP meetings to observe the use of OE information, completed evaluations of OE issues and events, and selected monthly assessments of the OE composite performance indicators. The inspectors review was to determine whether the licensee was effectively integrating OE experience into the performance of daily activities, whether evaluations of issues were proper and conducted by qualified personnel, whether the licensees program was sufficient to prevent future occurrences of previous industry events, and whether the licensee effectively used the information in developing departmental assessments and facility audits. The inspectors also assessed if corrective actions, as a result of OE experience, were identified and effectively and timely implemented.
Inspection Scope b.
In general, OE was effectively used at the station. The inspectors observed that OE was discussed as part of the daily station and pre-job briefings. Industry OE was effectively disseminated across the various plant departments and no issues were identified during the inspectors review of licensee OE evaluations. During interviews, several licensee personnel commented favorably on the use of OE in their daily activities.
Assessment No findings were identified.
Findings
.3 a.
Assessment of Self-Assessments and Audits The inspectors assessed the licensee staffs ability to identify and enter issues into the CAP, prioritize and evaluate issues, and implement effective corrective actions, through efforts from departmental assessments and audits.
Inspection Scope b.
The inspectors concluded that self-assessments, NOS audits, and other assessments were typically effective at identifying most issues. The inspectors concluded that these audits and self-assessments were generally completed in a methodical manner by personnel knowledgeable in the subject area. Corrective actions associated with the identified issues were implemented commensurate with their safety significance.
Assessment The inspectors also observed that issues identified in self-assessments and audits were captured in the CAP. For example, the NOS organization was effective in identifying a number of issues needing management attention and utilized a low threshold placing these findings into the CAP.
No findings were identified.
Findings
.4 a.
Assessment of Safety Conscious Work Environment The inspectors assessed the licensees safety conscious work environment through the reviews of the facilitys employee concern program implementing procedures, discussions with coordinators of the employee concern program, interviews with personnel from various departments, and reviews of issue reports. The inspectors also reviewed the results from Dresdens Semi-Annual Safety Culture reviews.
Inspection Scope b.
The inspectors determined that the plant staff were aware of the importance of having a strong SCWE and expressed a willingness to raise safety issues. No one interviewed had experienced retaliation for safety issues raised or knew of anyone who had failed to raise issues. All persons interviewed had an adequate knowledge of the CAP process.
Based on these limited interviews, the inspectors concluded that there was no evidence of an unacceptable SCWE.
Assessment The inspectors determined that the Employee Concerns Program was being effectively implemented. The inspectors noted that the licensee had appropriately investigated and taken constructive actions to address potential cases of harassment and intimidation for raising issues.
No findings were identified.
Findings 4OA6
.1 Management Meetings
On April 26, 2012, the inspectors presented the inspection results to Mr. D. Czufin, and other members of the licensee staff. The licensee acknowledged the issues presented.
Exit Meeting Summary
The inspectors confirmed that none of the potential report input discussed was considered proprietary.
ATTACHMENT:
SUPPLEMENTAL INFORMATION
KEY POINTS OF CONTACT
- D. Czufin, Site Vice President
Licensee
- S. Marik, Station Plant Manager
- D.J. Walker, CAP Coordinator
- R. Ruffin, Regulatory Assurance
- D. Anthony, NDES Manager
- J. Cady, Radiation Protection Manager
- D. Doggett, Emergency Preparedness Coordinator
- J. Fox, Design Engineer
- G. Graff, Nuclear Oversight Manager
- L. Jordan, Training Director
- B. Kapellas, Operations Director
- J. Knight, Director, Site Engineering
- M. Knott, Instrument Maintenance Manager
- D. Leggett, Regulatory Assurance Manager/Chemistry Manager
- G. Lupia, Corporate Buried Pipe Engineer
- T. Mohr, Supervisor, Engineering Programs
- P. Mankoo, Chemistry Manager
- M. McDonald, Maintenance Director
- T. Mohr, Engineering Program Manager
- P. OBrien, Regulatory Assurance - NRC Coordinator
- D. OFlanagan, Security Manager
- M. Otten, Operations Training Manager
- P. Quealy, Emergency Preparedness Manager
- R. Ruffin, Licensing Engineer
- J. Sipek, Work Control Director
- V. Earl, Regulatory Assurance
- J. Cameron, Chief, Division of Reactor Projects, Branch 6
Nuclear Regulatory Commission
LIST OF ITEMS
OPENED, CLOSED AND DISCUSSED
Opened
NCV Failure to Identify and Remove Diesel Fire Pump Battery Terminal Corrosion (Section 4OA2.1.b(3))
Closed
NCV Failure to Identify and Remove Diesel Fire Pump Battery Terminal Corrosion (Section 4OA2.1.b(3))