IR 05000298/2009007

IR 0500298-09-007 on 03/23/09 - 04/10/09 for Cooper Nuclear Station

ML091420470
Person / Time
Site:	Cooper
Issue date:	05/22/2009
From:	Greg Werner NRC/RGN-IV/DRS/PSB-2
To:	Minahan S Nebraska Public Power District (NPPD)
References
IR-09-007
Download: ML091420470 (32)

Text

UNITED STATES NUC LE AR RE G UL AT O RY C O M M I S S I O N May 22, 2009

SUBJECT:

COOPER NUCLEAR STATION - NRC PROBLEM IDENTIFICATION AND RELOLUTION INSPECTION REPORT 05000298/2009007

Dear Mr. Minahan,

On April 10, 2009, the U. S. Nuclear Regulatory Commission (NRC) completed a team inspection at Cooper Nuclear Station. The enclosed report documents the inspection findings, which were discussed on April 10, 2009, with Mr. Brian OGrady, Site Vice President, and other members of your staff.

The inspection examined activities conducted under your license as they relate to identification and resolution of problems, safety and compliance with the Commissions rules and regulations and with the conditions of your operating license. The team reviewed selected procedures and records, observed activities, and interviewed personnel. The team also interviewed a representative sample of personnel regarding the condition of your safety-conscious work environment.

This report documents one NRC-identified finding of very low safety significance (Green). The finding was determined to involve a violation of NRC requirements. Additionally, one licensee-identified violation, which was determined to be of very low safety significance, is listed in this report. However, because of the very low safety significance of the violations and because they were entered into your corrective action program, the NRC is treating these violations as noncited violations consistent with Section VI.A.1 of the NRC Enforcement Policy. If you contest these noncited violations, you should provide a 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 DC 20555-0001; with copies to the Regional Administrator, U.S. Nuclear Regulatory Commission, Region IV, 612 E. Lamar Blvd., Suite 400, Arlington, Texas, 76011-4125; the Director, Office of Enforcement, United States Nuclear Regulatory Commission, Washington DC 20555-0001; and the NRC Resident Inspector at Cooper Nuclear Station. In addition, if you disagree with the characterization of 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 IV, and the NRC Resident Inspector at Cooper Nuclear Station. The information you provide will be considered in accordance with Inspection Manual Chapter 0305.

Nebraska Public Power District -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 www.nrc.gov/reading-rm/adams.html (the Public Electronic Reading Room).

Sincerely,

/RA/

Gregory E. Werner, Chief Plant Support Branch 2 Division of Reactor Safety Dockets: 50-298 Licenses: DPR-46

Enclosure:

Inspection Report 05000298/2009007 w/Attachments: Supplemental Information Initial Information Request

REGION IV==

Docket: 50-298 License: DPR-46 Report: 05000298/2009007 Licensee: Nebraska Public Power District Facility: Cooper Nuclear Station Location: 72676 648A Avenue Brownville, Nebraska 68321 Dates: March 23 through April 10, 2009 Team Leader: Clyde Osterholtz, Senior Operations Engineer Inspectors: Michael Chambers, Resident Inspector James Drake, Senior Reactor Inspector Harry Freeman, Senior Reactor Inspector Approved By: Gregory E. Werner, Chief Plant Support Branch 2 Division of Reactor Safety-1- Enclosure

SUMMARY OF FINDINGS

IR 05000298/2009007; March 23 through April 10, 2009; Cooper Nuclear Station:

Biennial Baseline Inspection of the Identification and Resolution of Problems The team inspection was performed by three regional inspectors and one resident inspector. Two Green noncited violations were identified during this inspection. The significance of most findings is indicated by their color (Green, White, Yellow, Red) using Inspection Manual Chapter 0609, Significance Determination Process. Findings for which the significance determination process 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.

Identification and Resolution of Problems The team reviewed approximately 450 condition reports, work orders, engineering evaluations, root and apparent cause evaluations, and other supporting documentation to determine if problems were being properly identified, characterized, and entered into the corrective action program for evaluation and resolution. The team reviewed a sample of system health reports, self-assessments, trending reports and metrics, and various other documents related to the corrective action program.

The licensee appropriately evaluated industry operating experience for relevance to the facility and entered applicable items in the corrective action program. The licensee used industry operating experience when performing root cause and apparent cause evaluations. However, a majority of personnel interviewed during the safety-conscious work focus group interviews stated that they felt on occasion that licensee management had preconceived notions of root cause evaluation outcomes, and that sometimes the independent objectiveness of the root cause evaluations have been hindered. The licensee performed effective quality assurance audits and self-assessments, as demonstrated by self-identification of poor corrective action program performance and identification of ineffective corrective actions.

Cornerstone: Mitigating Systems

Green.

The team identified a noncited violation of 10 CFR Part 50, Appendix B,

Criterion V, Instructions, Procedures, and Drawings, for the licensees failure to follow the requirements of Procedure ENN OP 104, Operability Determinations.

Specifically, between 2005 and 2009 operations personnel failed to perform adequate operability determinations of degraded and potentially degraded conditions associated with essential Agastat time delay relays with internal foreign material contamination that either needed an immediate operability determination or needed more information to reasonable assurance of operability. This included a potential degraded condition of the installed essential Relay 27X15-1G that the inspection team noted had a trend similar to relays that had previously failed with internal foreign material contamination. The licensee documented this condition with CR-CNS-2009-02844 and replaced the potentially degraded relay ten days later.

This finding is more than minor because it affected the reliability objective of the equipment performance attribute of the Mitigating Systems Cornerstone to ensure the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences (i.e., core damage). The finding was determined to have a very low safety significance because the finding did not result in a loss of system safety function, an actual loss of safety function of a single train for greater than its Technical Specification allowed outage time, or screen as potentially risk significant due to a seismic, flooding, or severe weather initiating event. The cause of this finding is related to the problem identification and resolution crosscutting aspect associated with the corrective action program because licensee personnel failed to thoroughly evaluate conditions adverse to quality and perform meaningful operability determinations P.1(c) (Section 4OA2.5).

Licensee-Identified Violations

A violation of very low safety significance, which was identified by the licensee, has been reviewed by the inspectors. Corrective actions taken or planned by the licensee have been entered into the licensees corrective action program. This violation and corrective action tracking number (condition report number) is listed in Section 4OA7.

REPORT DETAILS

4OA2 Problem Identification and Resolution

The team based the following conclusions on a sample of corrective action documents that were initiated in the assessment period, which ranged from September 1, 2007, to the end of the on-site portion of this inspection on April 10, 2009.

.1 Assessment of the Corrective Action Program Effectiveness

a. Inspection Scope

The team reviewed approximately 450 condition reports (CRs), work orders, engineering evaluations, associated root and apparent cause evaluations, and other supporting documentation to determine if problems were being properly identified, characterized, and entered into the corrective action program for evaluation and resolution. The team reviewed a sample of system health reports, self-assessments, trending reports and metrics, and other documents related to the corrective action program.

The team evaluated the licensees efforts in establishing the scope of problems by reviewing selected logs, work requests, self-assessments results, audits, system health reports, action plans, and results from surveillance tests and preventive maintenance tasks. The team reviewed work requests and attended the licensees daily action review committee meeting to assess the reporting threshold, prioritization efforts, and significance determination process, as well as observing the interfaces with the operability assessment and work control processes when applicable. The teams review included verifying the licensee considered the full extent of cause and extent of condition for problems, as well as how the licensee assessed generic implications and previous occurrences. The team assessed the timeliness and effectiveness of corrective actions, completed or planned, and looked for additional examples of similar problems. The team conducted interviews with plant personnel to identify other processes that may exist where problems may be identified and addressed outside the corrective action program.

The team also reviewed corrective action documents that addressed past NRC-identified violations to ensure that the corrective actions addressed the issues as described in the inspection reports. The team considered risk insights from both the NRCs and Cooper Nuclear Stations risk assessments to focus the sample selection and plant tours on risk significant systems and components. The team selected the vital alternating current distribution system. The samples reviewed by the team focused on, but were not limited to, this system. The team also expanded their review to include five years of evaluations involving the vital alternating current distribution system to determine whether problems were being effectively addressed. The team conducted a walkdown of this system to assess whether problems were identified and entered into the corrective action program.

b. Assessments

1. Assessment - Effectiveness of Problem Identification

The team concluded that the licensee effectively identified, evaluated, and prioritized corrective actions for conditions adverse to quality. The team concluded that the licensee implemented timely, effective corrective actions, although some examples, including three violations, indicate some continuing weakness in this area.

2. Assessment - Effectiveness of Prioritization and Evaluation of Issues

The team performed a five year review of problems associated with the vital alternating current distribution system. This review of condition reports back to 2005 found that the majority of vital alternating current distribution system issues were being appropriately screened and challenged. The majority of issues were of low level and were either closed to trend or at a level appropriate for a condition evaluation. Many of these issues were closed to a work order, but the team noted that both the parent and daughter documents had the necessary links to document the relationship. The team identified five examples of operability determinations that were either not performed or did not fully evaluate the basis for operability of potentially degraded, degraded and non-confirming conditions.

Example 1:

The team identified a history of multiple Agastat pneumatic timer relays with degraded and potentially degraded conditions due to internal foreign material contamination from 2005 to 2009. Many essential equipment protection applications use Agastat relays including the vital alternating current power distribution system. The identified examples included transformer undervoltage protection, as well as reactor vessel level blowdown applications. Most recently, on April 7, 2009, the licensee initiated CR-CNS-2009-2844 when the team identified that there was an emergency diesel generator Agastat relay installed in the plant, with trends similar to Agastat relays that had previously failed due to foreign material. The licensee concluded that the Agastat relay was potentially degraded and it was replaced with a solid-state relay ten days later. This was considered a Green noncited violation (see Section 4OA2.5).

The following four examples of green noncited violations for inadequate operability determinations were documented in Inspection Report 05000298/2008005.

Example 2:

Condition Report CR-CNS-2008-08538 was initiated to document that a piece of the service water Pump B suction bell had been discovered missing during an overhaul of the pump. The inspectors challenged the control room staff on the first two versions of the operability determination after which Version 3 provided a more rigorous engineering analysis. The inspectors determined that Version 3 of the operability determination correctly determined that service water Pump B was operable.

Example 3:

The inspectors identified a small oil leak on the reactor core isolation cooling pump outboard bearing oiler during reactor core isolation cooling operation. The first operability determination incorrectly evaluated the condition as a small oil leak from the larger turbine reservoir instead of the much smaller oiler reservoir. The control room staff then correctly evaluated the condition and documented the deficient operability

determination in CR-CNS-2008-08889. The inspectors determined that Version 2 of the operability determination correctly determined that reactor core isolation cooling operability was not affected by the condition.

Example 4:

Condition Report CR-CNS-2008-09017 was initiated to recommend an extent of condition inspection of a division one service water pump to check for another suction bell failure, as had been seen in service water Pump B and described in CR-CNS-2008-08538 (discussed above). The missing suction bell piece discovered on Pump B had been discovered during the investigation into an air binding event of Pump B due to a failure of the gland seal package on the pump. However, the extent of condition operability determination was incorrectly based on the other operating pumps not having any air binding indications, not on the missing piece of the Pump B suction bowl that was not readily apparent and was only discovered during disassembly of the pump. The inspectors challenged the control room staff with this issue, after which Version 2 of the operability determination was written, which properly justified the continued operability of the division one service water pumps.

Example 5:

The inspectors identified that leaks from the 250 VDC Battery 1A were corroding the battery racks and associated fasteners on December 12, 2008. Condition Report CR-CNS-2008-09094 initial operability determination described the rack corrosion as a cosmetic issue and does not threaten the structural strength of the battery rack. The inspectors challenged the justification for this statement, in that it provided no technical basis for the acceptability of the corrosion of the seismic structure supporting the battery, nor did it provide a basis for the assumption that the corrosion was only cosmetic in nature. After repeated conversations between the inspectors and the civil engineering staff, Version 2 of the operability determination evaluated the ability of the battery racks to survive a seismic event without the corroded fasteners. This analysis properly evaluated the condition as not affecting the operability of the 1A batteries. The licensee documented the inadequacy in the original operability determination in CR-CN-2008-09205.

The team also reviewed the sites top ten unit reliability improvement list and found that it included replacing the essential Agastat pneumatic relays with solid state relays. The inspection team noted that despite the licensees history of Agastat pneumatic time delay relay problems, this design change was not tracked within the licensees corrective action program. The licensee considered top ten list tracking sufficient based upon general good performance of the relay population, lack of significant safety impact on the station, and priority with respect to other plant equipment issues. The lower level symptoms of Agastat relays that were degraded but not failed were not considered when the Agastat timer problems were ranked in priority by the licensee. Therefore, the inspection team concluded that Agastat relays with erratic trends to be degraded equipment issues and should be tracked by the corrective action program. The licensee captured this observation by adding corrective Action 4 to CR-CNS-2008-01352 to track implementation of the solid state relay design change, for the replacement of twenty-two

(22) Agastat time delay relays installed in time critical applications, and revising the apparent cause evaluation to document this corrective action.

The team also reviewed corrective action implementation for CRs of the vital alternating current distribution system. The team noted overall that corrective actions were implemented to assure correction of conditions adverse to quality and to prevent

repetition of significant conditions adverse to quality. There was one example the inspection team found of an inadequate corrective action to prevent recurrence of a loose switch that prevented a vital alternating current breaker from operating. The action was to add a step to check for loose switches in the breaker maintenance procedure.

However, the action did not capture all lessons learned when the licensee performed extent of condition checks of loose interlock switches in 20 other risk significant breakers essential breakers. During the interlock switches tightness checks numerous problems with stripped screws and determining the correct torque value for the switch mounting screws had to be resolved by the licensee maintenance and engineering staff. None of these lessons learned were included in the breaker maintenance procedure change, which lowered the effectiveness of a corrective action designed to prevent recurrence.

This observation was documented in CR-CNS-2009-2884.

The team found that the root cause analyses reviewed were thorough and appropriately considered extent of condition, generic issues, and previous occurrences. Condition Review Oversight Group reviews were detailed and ensured that corrective actions addressed the identified causes. For significant conditions adverse to quality, the station identified corrective actions to prevent recurrence. The team reviewed 22 of 30 root cause evaluations that were completed during the assessment period. The team felt the root cause determinations could have been more thorough in four of these analyses.

For example, root cause Analysis CR-CNS-2008-00968, Revision 1, which was associated with the failure of the emergency diesel Generator 2 lube oil pump discharge piping, did not identify the root cause as a fatigue failure even though the licensee had two independent sources of data that identified this as the failure mechanism.

Subsequent to this failure, on January 27, 2009, the same discharge piping failed on emergency diesel Generator 1. This most recent failure was reviewed as part of a special inspection that will be documented in Inspection Report 05000298/2009008.

3. Assessment - Effectiveness of Corrective Action Program

Overall, the team concluded that Cooper Nuclear Generating Station effectively identified and corrected problems through their corrective action program. However, the team noted that work orders related to troubleshooting activities (initiated by a condition report to identify the cause of the failure) did not always adequately document the conclusions reached nor thoroughly document the purpose of the work order. In addition, the actions developed for one of the work orders appeared to have been developed based upon a pre-conceived notion of the cause of the failure rather that an attempt to determine the cause of the failure. Several of the work orders contained mistakes, which indicated a lack of attention to detail.

Example 1: The licensee developed maintenance work Order 4623424 to determine the source of unexpected voltage identified while performing test jack installation in Panel 9-42. The troubleshooting steps directed technicians to measure voltages at 14 different locations and provide expected readings. Of these readings, five were outside their expected range; however, the work order failed to document one of the readings (Step 18) being out of range. The licensee also indicated that the expected value listed in Step 19 should have been zero vice ~90V. The licensees assessment did not justify these unexpected readings or why these readings indicated that the voltages were induced. Through discussions with the engineering staff, the inspection team determined that the conclusion was reasonable.

Example 2: The licensee developed maintenance work Order 4669945 to troubleshoot why motor operated Valve RCIC-MOV-MO18, failed to operate when the control switch

was taken to close in the control room. The troubleshooting plan was revised twice and the licensee did not make a determination as to the cause of the failure to close but suspects that it was due to a failed starter.

This work order was based upon preventative maintenance work Order 4597707 to replace RCIC-MOV-MO18. While establishing the initial conditions for this work order in December 2008, the licensee discovered that the valve would not operate. When requested by the inspection team, the licensee could not find the official copy of this work order and noted that the official copy had not been archived. The licensee initiated CR-CNS-2009-02832 to document this missing work order.

Example 3: The licensee developed maintenance work Order 4631427 to troubleshoot a trip of reactor recirculation motor Generator A that occurred in May 2008 during post maintenance testing. Attachment 2 of Procedure 7.0.1.7, Troubleshooting Plant Equipment, was written to perform Procedure 14.1RR.303 (Division 1) to change the characterizer values in Controller RRFC-SIC-16A and to verify that the scoop tube position was correct for each speed input. However, the completed troubleshooting activities indicated that the applicable steps of 14.2RR.303 (Division 2) were completed.

Step 11 of the Attachment 2 directs that the new Y values obtained be provided to the design engineering department for DCN #08-0561 to Drawing 730E197BB, Sheet 6C.

The inspector noted that the new values listed in confirmation Steps 2 and 3 for Y3 and Y10 were not correctly translated into the appropriate design change notification or drawing in that the values listed for Y3 and Y10 in the confirmation steps were 20.000 and 102.000 respectively, while the values listed in the design change notification and drawing were 20.500 and 102.500 respectively.

The licensee determined that Procedure 14.1RR.303 was performed on May 7, 2008, under work Order 4549322 following maintenance and replacement of the controller and was also performed on May 8, 2008, under work Order 4631427 as part of the troubleshooting activities. The inspector also noted that the "as left" values listed on the procedure were the values that were translated into the appropriate design documents.

Example 4: The licensee developed maintenance work Order 4656469 to troubleshoot the transfer circuits for cooling water Pump A. The problem description states in part, investigate cause of . . . COOLING WATER PUMP A tripping, and the reason why . . .

COOLING WATER PUMP B, did not auto start. The troubleshooting steps appear to be aimed at determining why Pump B did not auto start and did not address why Pump A tripped off line. In addition, the readings taken were essentially what was expected and the comments entered by the technician state, continue trouble shooting on power relays to determine cause for A [sic] Pump not to start. The work order was closed without determining the cause of either failure.

The team also noted that the qualification of spare parts for safety-related applications was somewhat hindered in that the licensee was not referencing equipment vendor manuals for appropriate spare parts specifications when qualifying the parts for safety-related applications. The licensee indicated that qualification procedures would be revised to reference the vendor manuals.

The team noted that there were 22 CRs in the corrective action program open for greater than two years. The licensee indicated that the tracking system for flagging older issues in the corrective action program would be evaluated for enhancement, as well as the periodicity of review of older items to expedite their closure.

.2 Assessment of the Use of Operating Experience

a. Inspection Scope

The team examined the licensees program for reviewing industry operating experience, including reviewing the governing procedure and self assessments. A sample size of 75 out of 146 operating experience notifications that had been issued during the assessment period were reviewed to assess whether the licensee had appropriately evaluated the notification for relevance to the facility. The team then examined whether the licensee had entered those items into their corrective action program and assigned actions to address the issues. The team reviewed a sample of root cause evaluations and corrective action documents to verify if the licensee had appropriately included industry-operating experience.

b. Assessment Overall, the licensee appropriately evaluated industry operating experience for relevance to the facility and entered applicable items in the corrective action program. The licensee appropriately used industry operating experience when performing root cause and apparent cause evaluations. The licensee performed effective quality assurance audits and self-assessments, as demonstrated by self-identification of corrective action program deficiencies.

.3 Assessment of Self-Assessments and Audits

a. Inspection Scope

The team reviewed a sample size of three of five licensee corrective action program self-assessments, surveillances, and audits to assess whether the licensee was regularly identifying performance trends and effectively addressing them. The team reviewed audit reports to assess the effectiveness of assessments in specific areas. The team evaluated the use of self- and third party assessments, the role of the quality assurance department, and the role of the performance improvement group related to licensee performance. The specific self-assessment documents reviewed are listed in the

.

b.

Assessment The team concluded that Cooper Nuclear Station effectively utilized self- assessments and audits to identify and correct problems associated with their corrective action program.

.4 Assessment of Safety-Conscious Work Environment

a. Inspection Scope

The inspection team conducted six focus group interviews with 51 participating individuals. The interviewees represented various functional organizations and ranged across contractor, staff, and supervisor levels. The team conducted these focus group interviews to assess whether conditions existed that would challenge the establishment of a safety-conscious work environment at Cooper Nuclear Station.

b. Assessment The team concluded that the licensee maintained a safety-conscious work environment.

All personnel interviewed indicated that they would not hesitate to raise safety concerns or to approach their management if they felt a safety concern had been left unresolved.

However, approximately half of the personnel interviewed indicated that they would not use the employee concerns program to raise concerns. The majority of these individuals indicated that they would probably contact the NRC directly if a safety concern could not be resolved using their management chain. These individuals indicated that the employee concerns program was controlled by management, and therefore would probably not be effective if management itself was not properly addressing a safety issue. Additionally, approximately 20 percent of the personnel interviewed indicated they believed the employee concerns program only existed for administrative issues and not for resolution of nuclear safety concerns. Also, a majority of personnel interviewed indicated that they felt on occasion that licensee management had preconceived notions of root cause evaluation outcomes, and that sometimes the independent objectiveness of the root cause evaluations have been hindered. The licensee was evaluating appropriate actions to address these issues at the end of the inspection.

.5 Specific Issues Identified During This Inspection

(1) Failure to Follow Procedure Results in Inadequate Operability Determinations of Degraded Agastat Timer Relays.

Introduction:

The team identified a Green noncited violation of 10 CFR Part 50, Appendix B, Criterion V, Instructions, Procedures, and Drawings, for the licensees failure to follow the requirements of Procedure ENN OP 104, Operability Determinations.

Specifically, between 2005 and 2009 operations personnel failed to perform adequate operability determinations of degraded and potentially degraded conditions associated with essential Agastat time delay relays with internal foreign material contamination that either needed an immediate operability determination or needed more information to provide reasonable assurance for operability. This included a potential degraded condition of the installed essential Relay 27X15-1G that the inspection team noted had a trend similar to relays that had previously failed with internal foreign material contamination.

Description:

In 2004, root cause Report CR-CNS-2004-0009 investigated a problem with Relay 27X16-1G with an as-found time greater than the operability limit. This resulted in an unplanned entry into a Technical Specification Action Statement due to declaring emergency diesel Generator 2 inoperable. Relay 27X16-1G provides a time delay when the emergency diesel Generator 2 is tied to the Vital 4160 Volt G bus following a loss of coolant accident and loss of offsite power signal. This relay prevents the Division 2 Vital 4160 V G bus from de-energizing due to loss or degraded voltage during sequential loading of the emergency diesel generator.

Relay 27X16-1G had a history of performance problems related to setpoint drift, which was significantly greater than its divisional counterpart relay for the Division 1 emergency diesel generator. The effects of vibration, temperature and mechanical transients were all tested and found not to be the cause of Relay 27X16-1G performance problems. The 2004 solution was to increase the nominal setpoints to provide a greater margin for setpoint drift. While this increased margin addressed the symptoms, the underlying cause was not identified by the 2004 investigation.

On May 25, 2005, the licensee initiated CR-CNS-2005-03971 for Agastat Relay K5B as-found setpoint high outside the Technical Specification allowable value. Relay K5B functions to delay reactor pressure vessel blow down on low level in order to allow the high pressure coolant injection system to restore level following a loss of coolant accident. Like Relay 27X16-1G, Relay K5B calibration trend history exhibited significantly more setpoint drift than its divisional counterpart Relay K5A. Relay K5B was replaced and foreign material was found obstructing the relay internal time delay restricting orifice. From the trend history and evaluation of the foreign material, the licensee determined the foreign material was introduced during the manufacturers assembly process. During the extent of condition evaluation for Relay K5B, the licensee identified that Relay 27X16-1G was potentially degraded based on the erratic trend history; however, the licensee did not perform an operability determination.

On June 11, 2005, the licensee originated Work Order 4445800 and CR-CNS-2005-04292 as a proactive opportunity to replace Relay 27X16-1G due to an erratic trend history similar to Relay K5B erratic trends due to foreign material. The operability determination stated that based on the Relay 27X16-1G past trends the maximum setpoint drift between the monthly surveillances was small enough that future setpoint drift between monthly surveillances would not exceed operability limits and therefore, Relay 27X16-1G was considered operable.

The operability determination did not evaluate foreign material acting as a random factor in delay timing. The Agastat relay time delay is provided by a small bleed orifice that controls the bleed of air from the relay diaphragm. Foreign material moving in the relays small bleed orifices could provide a random element into the bleed down times.

Therefore, predicting future performance on past results without determining probability of failure did not provide a reasonable assurance of future operability if foreign material was present in the relay.

On December 19, 2005, during monthly testing, Relay 27X16-1G timed high outside the calibration limit though inside the operability limit. When the relay was adjusted to lower the setpoint to within the calibration limit, subsequent testing to verify the adjustment resulted in the relay timing high outside the operability limit. Emergency diesel Generator 2 was declared inoperable as a result. Further adjustments were made to the relay until the relay timer results were acceptable, allowing the emergency diesel generator to be declared operable. Though CR-CNS-2005-09334 was initiated on this event, the licensee did not evaluate the degraded condition of the relay contrary to the requirements of Procedure ENN-OP-104, Operability Determinations. Work Order 4445800 replaced Relay 27X16-1G in November 2006; however, the licensee did not perform any evaluation or examination of the relay to determine the cause of the erratic operation.

The licensee initiated CR-CNS-2008-01352 on March 3, 2008, when they found Agastat Relay 27X15-1F out of calibration and repeated calibration adjustments were unsuccessful, due to erratic timer results. The operations shift manager declared the relay inoperable and emergency diesel Generator 1 inoperable. Agastat Relay 27X15-1F provides a 7.5 second delay prior to a system trip signal to the vital emergency Transformer 4160 Volt critical bus feeder Breaker 1FS, on indications of degraded (low)voltage. Emergency diesel generator Breaker EG1, auto-closure is prevented if Breaker 1FS does not trip when required.

The inspection team noted that despite a step change increase in the variance of Relay 27X15-1F trends back in January 2005 there was not an operability determination to assess this indication of a potentially degraded relay. The licensee apparent cause evaluation, Version 2, determined that foreign material obstruction of Agastat relay restricting orifice from original manufacturer assembly caused the failure. The licensee reviewed past performance of Relay 27X15-1F and its divisional counterpart, Relay 27X15-1G with conclusions that the, trend of setpoint performance of these relays does not indicate that the failure of Relay 27X15-1F was predictable. This conclusion only considered performance problems for setpoints found outside calibration limits, and failures for as-found setpoints outside operability limits. The licensee evaluation also concluded that the divisional counterpart Relay 27X15-1G timer trends, exhibited, in general more stable performance since installation, but does exhibit more erratic operation following January 2005.

The inspection team reviewed the Agastat relays historical trends setpoint variance and noted the increased variance (more erratic timer performance) did precede relay failures.

The licensee engineering team pointed out that there has been only two actual failures of approximately 240 Agastat time delay relays over the last several years. They failed to consider that only approximately 22 relays have time critical functions, that the 2004 relay problems were probably foreign material related, and that other relays exhibited degraded performance that did not rise to the level considered a failure by the licensees program. The inspection team noted that failed Relay 27X15-1F trends statistical variance had exhibited a step change increase in January 2005, indicating degraded relay timing behavior. The licensee did not consider this step change an adverse condition, and it was not documented in the corrective action program and therefore, it did not receive an operability determination.

The inspection team noted that the divisional counterpoint to Relay 27X15-1F, essential Relay 27X15-1G, had a similar erratic trend associated with internal foreign material contamination of previously failed relays. The licensee initiated CR-CNS-2009-02844 for the potentially degraded condition Relay 27X15-1G. The inspection team then reviewed the initial operability determination on Relay 27X15-1G and noted it did not address the potential failure mode of foreign material and that the trend of past setpoint data did not necessarily support a prediction of future failure free operation. The licensee subsequently determined the probability of the potentially degraded relay failing due to foreign material was not significant but did decide to replace the relay within the next ten days. Based on the small probability of failure and the relay was scheduled to be replaced in the next ten days, the inspection team concurred that was little safety significance with the potentially degraded relay. The licensee documented the inspection teams operability determination questions in Condition Report CR-CNS-2009-2885.

Analysis:

The performance deficiency associated with this finding involved the licensees failure to follow the requirements of Procedure ENN-OP-104, Operability Determinations. Specifically, the team identified examples from 2005 through 2009 in which the shift manager failed to document the basis for operability when a potentially degraded or nonconforming condition had been identified with essential Agastat delay timer relays. This finding is more than minor because it affected the reliability objective of the equipment performance attribute of the Mitigating Systems Cornerstone to ensure the availability, reliability, and capability of systems that respond to initiating events to

prevent undesirable consequences (i.e., core damage). Using Manual Chapter 0609.04, Phase 1 - Initial Screening and Characterization of Findings, the finding was determined to have a very low safety significance because the finding did not result in a loss of system safety function, an actual loss of safety function of a single train for greater than its Technical Specification allowed outage time, or screen as potentially risk significant due to a seismic, flooding, or severe weather initiating event. The cause of this finding is related to the problem identification and resolution crosscutting aspect associated with the corrective action program because licensee personnel failed to thoroughly evaluate conditions adverse to quality and perform meaningful operability determinations P.1(c).

Enforcement.

Title 10 of the Code of Federal Regulations Part 50, Appendix B, Criterion V, Instructions, Procedures, and Drawings, requires, in part, that activities affecting quality shall be prescribed by documented instructions, of a type appropriate to the circumstances and shall be accomplished in accordance with these instructions.

The assessment of operability of safety-related equipment was an activity affecting quality and was implemented by Procedure ENN-OP-104, Operability Determinations, Revision 2. Step 4.2.1 requires that the shift manager document the basis for operability when a degraded or nonconforming condition exists. Step 1.1 requires that reasonable assurance exist that equipment will perform its design function until corrective action or further investigation can be completed. Contrary to these requirements, the shift manager did not document the bases for operability or did not provide a reasonable assurance of operability for degraded and potentially degraded Agastat Relays, 27X16 1G, 27X15-1G and 27X15-1F from 2005 to 2009. Because the finding is of very low safety significance and has been entered into the licensees corrective action program as Condition Report CR-CNS-2009-02885, this violation is being treated as a noncited violation consistent with Section VI.A of the Enforcement Policy:

NCV 05000298/2009007-01, Failure to Follow Procedure Results in Inadequate Operability Determinations of Degraded Agastat Timer Relays.

4OA6 Meetings

Exit Meeting Summary

On April 10, 2009, the team presented the inspection results to Mr. Brian OGrady and other members of the licensee staff. The licensee acknowledged the issues presented.

The inspector asked the licensee whether any materials examined during the inspection should be considered proprietary. No proprietary information was identified.

4OA7 Licensee-Identified Violations

The following violation of very low safety significance (Green) was identified by the licensee and is a violation of NRC requirements which meet the criteria of Section VI of the NRC Enforcement Policy, NUREG-1600, for being dispositioned as a noncited violation (NCV):

Title 10 CFR 20.1501 requires the licensee to adequately survey and evaluate the magnitude and extent of radiation levels. Contrary to the above, on December 30, 2008, a radiation protection technician discovered radiation dose rates of 500 millirem per hour at one foot near the spent fuel storage pool gates. This constituted a high radiation area as defined by licensee Technical Specification 5.7.1. The high radiation area was not

originally identified during initial surveys taken on December 10, 2008. The high radiation area was caused by control rod blades on hangers on the northwest wall of the spent fuel pool in close proximity to the gates for the fuel transfer channel. The issue was more than minor because it was associated with the Program/Process attribute of the Occupational Radiation Safety Cornerstone and affected the cornerstone objective to ensure adequate protection of worker health and safety from exposure to radiation. The issue represents a finding of very low safety significance because it did not involve as low as is reasonably achievable planning or work controls, there was no overexposure, nor did a substantial potential for an overexposure exist given the radiological conditions in the area and the workers response to the electronic dosimeter alarm. The licensee's ability to assess worker dose was not compromised.

SUPPLEMENTAL INFORMATION

KEY POINTS OF CONTACT

Licensee Personnel

J. Austin, Manager, Emergency Preparedness

B. Beilke, Manager, Chemistry

M. Boruch, Site Human Resources Manager

M. Boyce, Manager, Projects

T. Carson, Manager, Maintenance

W. Chapin, Outage Manager

D. Clark, Assistant Operations Supervisor

R. Estrada, Manager, Corrective Action and Assessments

J. Flaherty. Senior Licensing Engineer

J. Furr, Manager, Quality Assurance

W. Green, Procurement Engineering Supervisor

A. Johnson, Training Instructor

A. Kleckinger, Construction Superintendent, Nuclear Projects

G. Kline, Director, Engineering

K. Kreifels, Maintenance Support Supervisor

J. Kulins, Security Shift Supervisor

G. Mace, Nuclear Asset Manager

A. Martinez, Stores Supervisor

E. McCutchen, Senior Licensing Engineer

B. OGrady, Site Vice President

D. Oshlo, Manager, Radiation Protection

D. Parker, Assistant Maintenance Manager

R. Penfield, Manager, Operations

S. Rezub, Staff Health Physicist

D. Sealock, Manager, Training

K. Tanner, Radiological Shift Supervisor

J. Teten, Chemistry Supervisor

D. VanDerKamp, Manager, Licensing

D. Willis, Manager, Plant Operations

A. Zaremba, Director, Nuclear Safety Assurance

NRC personnel

N. Taylor, Senior Resident Inspector

G. Werner, Chief, Plant Support Branch 2, Division of Reactor Safety

LIST OF ITEMS

Opened

None

Opened and Closed

05000298/2009007-01 NCV Failure to Follow Procedure Results in Inadequate Operability Determinations of Degraded Agastat Timer Relays (Section 4OA2.e)

A-1- Attachment

Closed

None

Discussed

None