IR 05000348/2005008

IR 05000348-05-008 & 05000364-05-008, on 08/08/2005 - 08/12/2005 and 08/22/2005 - 08/26/2005; Joseph M. Farley Nuclear Plant, Units 1 and 2; Identification and Resolution of Problems

ML052700431
Person / Time
Site:	Farley
Issue date:	09/27/2005
From:	Widmann M NRC/RGN-II/DRP/RPB2
To:	Stinson L Southern Nuclear Operating Co
References
IR-05-008
Download: ML052700431 (31)

Text

ber 27, 2005

SUBJECT:

JOSEPH M. FARLEY NUCLEAR PLANT - NRC PROBLEM IDENTIFICATION AND RESOLUTION INSPECTION REPORT 05000348/2005008 AND 05000364/2005008 ERRATA LETTER

Dear Mr. Stinson:

On September 24, 2005, the U. S. Nuclear Regulatory Commission (NRC) issued the subject inspection report for the Joseph M. Farley Nuclear Plant. In reviewing this report, it was noted that we failed to identify the cross-cutting aspects for the documented findings. Accordingly, we are providing a revised inspection report with the cross-cutting aspects identified. This information will be included in the publicly accessible Plant Issues Matrix (PIM). The enclosed revision supercedes the inspection report issued on September 24, 2005, in its entirety (ADAMS Accession Number ML052660339). Please replace the inspection report with the enclosed revision.

In accordance with 10 CFR 2.390 of the NRC's "Rules of Practice," a copy of this letter and its enclosure will be available electronically for public inspection in the NRC Public Document Room or from the Publicly Available Records (PARS) components 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).

I apologize for any inconvenience this omission may be caused. If you have any questions, please contact me at (404) 562-4550.

Sincerely,

\RA\

Malcolm T. Widmann, Chief Reactor Projects Branch 2 Division of Reactor Projects Docket Nos.: 50-348 and 50-364 License Nos.: NPF-2 and NPF-8

Enclosure:

NRC Inspection Report 05000348/2005008 and 05000364/2005008 w/Attachment: Supplemental Information

REGION II==

Docket Nos: 50-348 and 50-364 License Nos: NPF-2 and NPF-8 Report Nos: 05000348/2005008 and 05000364/2005008 Licensee: Southern Nuclear Operating Company, Inc.

Facility: Joseph M. Farley Nuclear Plant, Units 1 and 2 Location: 7388 N. State Highway 95 Columbia, AL 36319 Dates: August 8 - 12, 2005, and August 22 - 26, 2005 Inspectors: R. Carroll, Senior Project Engineer (Lead Inspector)

J. Baptist, Resident Inspector - Farley R. Reyes, Resident Inspector - Crystal River A. Nielsen, Health Physics Inspector Approved by: Malcolm T. Widmann, Chief Reactor Projects Branch 2 Division of Reactor Projects Enclosure

SUMMARY OF FINDINGS

IR 05000348/2005-008 and 05000364/2005-008; 08/08/2005 - 08/12/2005 and 08/22/2005 -

08/26/2005; Joseph M. Farley Nuclear Plant, Units 1 and 2; Identification and Resolution of Problems.

The inspection was conducted by a senior project engineer, two resident inspectors, and a health physics inspector. Three Green findings were identified of which two were non-cited violations (NCVs). The significance of most findings is indicated by their color (Green, White,

Yellow, Red) using 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 NRC's program for overseeing the safe operation of commercial nuclear power reactors is described in NUREG-1649, Reactor Oversight Process, Revision 3, dated July 2000.

Problem Identification and Resolution (PI&R)

The team determined that the licensee was generally effective in identifying problems and entering them into the corrective action program (CAP). The threshold for problem identification was determined to be low. CAP-related audits were effective in identifying deficiencies for resolution. Condition Report trending under the CAP has had success in bringing about corrective actions for identified adverse trends. The team determined that the licensee properly prioritized issues entered into the CAP. Generally, the licensee performed adequate evaluations that were technically accurate and sufficiently detailed. Corrective actions developed and implemented for problems were generally timely, effective, and appropriate to the problem. One Green finding for failure to correct a long-standing condition adverse to quality and two Green non-cited violations for a failure to promptly identify a condition adverse to quality and inadequate corrective actions to preclude recurrence were identified. In addition, several examples of minor problems were identified including equipment failures that were inappropriately classified as not being functional failures, industry operating experience that was ineffectively evaluated, and past operability determinations that lacked proper documentation. Management emphasized the need for staff to identify and resolve issues using the CAP. A safety conscious work environment was evident.

Cornerstone: Mitigating Systems

Green.

An NRC-identified non-cited violation of 10 CFR Part 50, Appendix B, Criterion XVI, was identified for failure to take corrective actions to preclude repetition of a significant condition adverse to quality. Specifically, corrective actions taken to develop a solid state protection system (SSPS)/7300 troubleshooting guideline following a Unit 2 SSPS/7300 troubleshooting-related reactor trip on April 12, 2004, was inadequate to preclude the recurrence of another SSPS/7300 troubleshooting-related event on April 28, 2005.

This finding is more than minor because it affects the Mitigating Systems Cornerstone attribute of equipment performance and adversely impacted the cornerstone objective in that the SSPS/7300 troubleshooting guidance did not provide the necessary steps to facilitate timely (i.e., within the TS LCO) determination of a SSPS/7300 process channel failure. This finding is of very low safety significance because the B train of SSPS was maintained operable at all times. This finding has the cross-cutting aspect of Problem Identification and Resolution in the area of Corrective Actions. (Section 4OA2c.(2)(b))

Cornerstone: Barrier Integrity

Green.

A self-revealing non-cited violation of 10 CFR 50, Appendix B, Criterion XVI,

Corrective Action, was identified for failure to identify a significant condition adverse to quality. Specifically, following the July 15, 2003, trip of the 1A containment spray pump room cooler, the licensee failed to identify an existing degraded time delay relay.

Consequently, for the period between July 15, 2003, until corrected on May 1, 2004, the degraded condition of the 1A containment spray pump room cooler rendered it vulnerable to run/stop/hot restart scenarios that could be encountered during the response to a large break loss of coolant accident (LOCA).

This finding is more than minor because it affects the Barrier Integrity Cornerstone attribute of Barrier Performance and impacted the cornerstone objective in that tripping of the room cooler could result in loss of the 1A containment spray pump safety function due to overheating. This finding is of very low safety significance (Green) because the 1B containment spray pump and room cooler and all containment coolers were available to ensure containment barrier integrity would be maintained in the event of a large break LOCA or containment over pressure challenge. This finding has the cross-cutting aspect of Problem Identification and Resolution in the area of Identification. (Section 4OA2c.(2)(a))

Green.

An NRC-identified finding was identified for untimely resolution of excessive air flow problems on the Unit 1 and Unit 2 Containment Air Particulate Radiation Monitors (R-11). Excessive air flow through the moving filter paper caused the monitor to become inoperable on numerous occasions since 1990. When R-11 was out of service, the ability to detect low-level reactor coolant system (RCS) leakage was degraded.

This finding is more than minor because it is associated with the RCS Equipment and Barrier Performance Attribute of the Barrier Integrity Cornerstone and adversely affects the cornerstone objective in that the ability to detect low-level RCS leakage that may indicate pressure boundary degradation was reduced. This finding could not be evaluated using the Significance Determination Process (SDP) in accordance with IMC 0609 because the SDP for the RCS barrier only applied to a degraded barrier; not the ability to detect a degraded barrier. Therefore, this finding was reviewed by regional management and determined to be of very low safety significance (Green) because alternate methods of detecting low-level RCS leakage were available whenever R-11 was out of service. This finding has the cross-cutting aspect of Problem Identification and Resolution in the area of Resolution. (Section 4OA2c.(2)(c))

B. Licensee-identified Violations None

REPORT DETAILS

4OA2 Problem Identification and Resolution (PI&R)

a. Effectiveness of Problem Identification

(1) Inspection Scope The team reviewed selected condition reports (CRs) initiated since the previous NRC PI&R inspection, conducted September 2003, to verify that problems were being properly identified, appropriately characterized, and entered into the corrective action program (CAP). The reviews primarily focused on issues associated with five risk significant plant safety system areas: nuclear service water (SW); auxiliary feedwater; component cooling water; emergency core cooling systems (ECCS); and vital electrical systems. In addition to the system reviews, the team selected a sample of CRs that were related to radiation protection and emergency preparedness to ensure coverage of those cornerstones. The team also reviewed those CRs associated with licensee event reports and findings identified in NRC inspection reports (IRs) issued since the last PI&R inspection.

The team reviewed completed maintenance work orders (WOs), system health reports, and the Maintenance Rule (MR) database for the five selected system areas to verify that equipment deficiencies were being appropriately entered into the CAP and the MR program. The team conducted walkdowns of equipment associated with the selected systems to assess the material condition and to look for any deficiencies that had not been entered into the CAP. The team reviewed temporary modifications, the main control room deficiency list, operator workaround list, failed surveillances and any acceptance criteria changes, control room operator logs, and the employee concerns program to verify that equipment deficiencies (especially those involving the selected systems) were entered into the CAP.

The team reviewed selected industry operating experience (OE) items, including NRC generic communications, to verify that both types were appropriately evaluated for applicability and whether issues identified through these reviews were entered into the CAP. The team reviewed several licensee audits (focusing primarily on problem identification and resolution) to verify that findings were entered into the CAP and to verify that these findings were consistent with the NRCs assessment of the licensees CAP. Trending of CRs under the CAP was also reviewed to determine if licensee-identified trends were captured for resolution and if CAP statistics indicated any trends that were not identified by the licensee.

The team attended several daily management update and site corrective action program coordinator (CAPCO) meetings, as well as a corrective action review board meeting to observe management and department CAPCO oversight functions in the corrective action process. The team also interviewed personnel from operations, maintenance, engineering, health physics, and emergency preparedness to evaluate their threshold for identifying issues and entering them into the CAP. Documents reviewed are listed in the Attachment.

(2) Assessment The team determined that the licensee was effective in identifying problems and entering them into the CAP. There was, however, one issue identified involving the July 16, 2004, remote shutdown capability test of the 1C SW pump, in which the necessity to cycle its associated switch twice before starting was recorded on the surveillance test result sheet (STRS) of FNP-1-24.20; but, not in a CR where it could be evaluated and trended under the CAP. Performance/documentation of such switch cycling/cleaning on the STRS was also found to be permitted in precaution/limitation 4.4 of FNP-1-STP-73.1, Hot Shutdown Operability Verification; thereby, making it potentially vulnerable to bypassing the CAP as well. To address this and related switch cycling/cleaning potential vulnerabilities, the licensee generated CRs 20055108397 and 2005203550.

Based on observed samples, independent walkdowns, and staff interviews, the threshold for problem identification was low. CRs provided complete and accurate characterization of the subject issues. Equipment performance issues involving maintenance effectiveness were for the most part being appropriately identified and entered into the CAP. However, the team identified two CRs (i.e., CR 2003003388, Degraded 1C Diesel Generator Speed Signal Generator, and CR 2005104677, Failure of Service Water Battery Charger #3 to Load) where the associated equipment failure was inappropriately categorized as not being a functional failure. The licensee generated CRs 2005108425 and 2005108446, which acknowledged the mis-classifications and confirmed that the respective functional failures would not have caused (past or present) the MR performance criteria for the affected functions to be exceeded.

With the exception of the two examples discussed below, the licensee was effective in evaluating internal and external industry operating experience items for applicability and entering issues into the CAP:

• NRC IR 05000348,364/2004004 identified that the licensees response to Information Notice (IN) 94-68, Safety-Related Equipment Failures Caused By Faulted Indicating Lamps, was narrow in scope and specifically did not address the diesel generators (DGs). Although there had been a number of occurrences recorded in CRs involving the DGs since 2000, actions taken had focused on restoring diesel operability and more careful bulb replacement rather than eliminating the problem. The team verified that the licensee had recently completed modifications to eliminate this problem on both the diesels and the main steam atmospheric reliefs, as well as began an in-depth review of the IN to determine if similar vulnerabilities exist.

• As documented in NRC Triennial Fire Protection (TFP) IR 05000348,364/2005006, the licensee inappropriately made the assumption that a fire could not cause the spurious opening of both the inboard and outboard reactor coolant system (RCS)-to-residual heat removal (RHR) system supply isolation valves. The effects of fire on these valves was discussed in INs 87-50, Potential Loss of Coolant Accident (LOCA) at High and Low Pressure Interfaces From Fire Damage, 92-18 Potential For Loss of Remote Shutdown Capability During a Control Room Fire, and 99-17, Problems Associated With Post Fire Safe Shutdown Circuit

Analysis.

The licensee did not properly evaluate these INs and inappropriately concluded they were not vulnerable to this failure.

Consequently, Units 1 and 2 had maintained both valves in the two RCS-to-RHR supply lines energized making them susceptible to a breach in the high pressure - low pressure interface boundary between the RCS and RHR systems. When the condition was identified during the April 2005 TFP inspection, the licensee was in the process of reviewing the issue again under RIS 2004-03, Risk Informed Approach for Post Fire Safe Shutdown Associated Circuit Inspections. Subsequently, on April 29, 2005, the licensee de-energized one train of valves on both units to prevent inadvertent actuation due to a fire.

CAP-related audits performed by Performance Evaluation, Quality Assurance (QA), and department CAPCOs were effective in identifying issues and entering these deficiencies into the CAP for resolution. Site management was involved in the CAP and focused attention on significant plant issues.

CR trending under the CAP has had success in bringing about corrective actions for identified adverse trends; however, trend identification was primarily keyed on tripping established thresholds based on increases in CR populations for a given area.

Consequently, issues common to smaller CR populations, such as the heat exchanger problems noted in NRC IR 05000348,364/2005003 or missed procedural interdependencies and out-of-specification Agastat testing results noted during the teams CR reviews, may go undetected without rigorous reviews at either end of the CR process. For the examples noted, all were confirmed by the team to have been captured for resolution by means other then the formal trending process (e.g., system engineer, CR evaluation, etc.). It was noticed that the site CAPCO recently began identifying repeat issues for possible adverse trends; but, as of the time of this inspection, the need to perform the intended trend assessments had not been captured in a CR. NRC IR 05000348,364/2005003 also documented the resident inspectors questioning the validity of the justifications used in dispositioning 14 potential adverse trends identified in the November 2004 - January 2005 CAP trend report as no adverse trend. The teams review of the February - April 2005 CAP trend report revealed that during the managers trend report review two of the subject areas (i.e., fire equipment and performance monitoring) were appropriately reclassified as actual adverse trends.

In addition, CR 2005106889 identified areas for improvement related to data trending and more timely/in-depth management review (i.e., addition of tertiary event codes and review of the trend report outside the weekly managers meeting within 45 days). The potential adverse trends for the period of May - July 2005, including the need for assessment before capturing them in the associated CAP trend report, had not been identified in CRs as of the end of this inspection; therefore, corrective action effectiveness could not be assessed.

b. Prioritization and Evaluation of Issues

(1) Inspection Scope The team reviewed selected CRs in order to verify that the licensee properly classified and evaluated the problems in accordance with procedure NMP-GM-002, Corrective Action Program. Accordingly, the teams review also assessed if the licensee determined the apparent cause (root and contributing causes for significant conditions adverse to quality) of problems and adequately addressed operability, reportability, common cause, generic concerns, and extent of condition. More than a third of the CRs reviewed were classified as either Severity Level (SL) 2 (requiring a root cause and corrective actions to prevent recurrence) or SL 3 (requiring an apparent cause and corrective actions to reduce the likelihood of recurrence). There were no SL1 CRs in the overall population from which the CRs reviewed were selected.

(2) Assessment With the exception of CRs 200400795 and 2003000917, the team determined that the licensee properly prioritized issues entered into the CAP. The CRs in question were associated with non-cited violations and should have been prioritized as SL 3 (versus SL 5 and SL 4, respectively) in accordance with NMP-GM-002. This was considered administrative in nature since the required apparent cause was performed for each one.

Overall, the licensee performed adequate evaluations that were technically accurate and sufficiently detailed. Consistent with QA audit findings, the team noted the following exceptions:

• CR 2003000172, Unit 2 Solid State Protection System (SSPS) B Train Failure: During surveillance testing of the Unit 2 SSPS B Train on January 29, 2003, and on March 21, 2003, the Logic C test failed at position 14 (Lo-Lo level start of the turbine driven auxiliary feedwater pump (TDAFWP)). The licensee performed a root cause analysis, but found there was not enough information available to make a root cause determination. Therefore, various corrective actions were identified in the CR to be performed so that data could be gathered in order to determine a root cause.

However, the team found that some of these corrective actions (i.e., resistance check of logic switches to verify proper operation, failure analysis of the SSPS card, visual inspections of card edge connections, and investigation into the cause of a bad card selected from the warehouse) had not been completed. As a result, the root cause was never determined; therefore, no past operability determination of the TDAFW pump could be made. The CR described reasons why some of the actions were not completed (e.g., too man power intensive, too costly, etc.). However, the decision not to perform these corrective actions was not communicated to the root cause group as required by NMP-GM-002. Furthermore, the licensees root cause effectiveness review had determined that the corrective actions were effective when some of them had never been completed and a root cause had never been determined. When questioned about these discrepancies, the licensee initiated CR 2005108442.

• CR 2004002293, Gas Accumulation in Suction of the 2B Coolant Charging/High Head Safety Injection (HHSI) Pump: The licensee had identified that the 2B HHSI pump discharge check valve had a flaw which allowed approximately 40 gallons per minute (GPM) of reverse flow through the pump when idle. A formal operability determination had been performed which determined that HHSI pump discharge flows had been balanced within established limits. However, documentation was not readily available to demonstrate that the effects of the idle pump (i.e., the reverse flow) had been considered with respect to post-accident operation of HHSI pump 2A and/or 2C.

Informal/uncontrolled information was eventually provided to the team that substantiated proper post-accident operation of the 2A and 2C HHSI pumps, but this information was not inherent to the resolution of CR 2004002293 or any of its supporting justifications.

• CR 2004001281, 1A Containment Spray Pump Room Cooler Failure: The licensee determined that a degraded time delay relay was the cause of the July 15, 2003, and March 23, 2004, run/stop/hot restart trips experienced on the 1A containment spray pump room cooler. Accordingly, the March 23, 2004, event was appropriately identified by the licensee as a maintenance preventable failure. However, it was apparent that the licensee had not considered past operability of the room cooler with respect to its vulnerability to run/stop/hot restart scenarios that could be encountered during the response to a large break loss of coolant accident (LOCA). (This condition is further discussed in Section 4OA2c.(2)(a).)

Troubleshooting was considered an essential tool in problem evaluation. NRC IR 05000348,364/2004005 documented an observation of inconsistent troubleshooting activities for 4160 volt breakers. The team also identified other troubleshooting-related issues involving the evaluation/cause determination of failures in the SSPS/7300 process channels in Unit 2 and the failures of non-vital inverter 2F. SSPS/7300 troubleshooting is discussed further in Section 4OA2c.(2)(b) of this report. With respect to the 2F inverter, troubleshooting efforts were unable to preclude two additional failures (i.e., transfers to bypass on July 17 and 27, 2005) since its failure on July 1, 2005, which resulted in returning to a MR (a)(1) status for the second time in two years. Suspecting all three failures were the result of an intermittent transistor failure, the affected static switch card was replaced after the third failure before returning the inverter to service in August 2005. At that time, a more methodical approach to troubleshooting the 2F inverter was implemented that included monitoring via an attached recorder. No further failures of the 2F inverter had occurred by the conclusion of the inspection.

c. Effectiveness of Corrective Actions

(1) Inspection Scope The team evaluated selected CRs to verify that the licensee had identified and implemented timely and appropriate corrective actions to address problems. The team determined whether the corrective actions were appropriate for the described problem, as well as properly documented, assigned, and tracked to ensure completion. Selected corrective actions were sampled for detailed review to independently verify that corrective actions were implemented as intended. The sample selected for verification included corrective actions associated with NRC findings and others from CRs associated with the focus systems. Additionally, the team reviewed a sampling of the oldest CRs to determine if implementation delays were appropriately justified.

(2) Assessment Corrective actions developed and implemented for problems were generally timely, effective, and appropriate to the problem. NRC IR 05000348,364/ 2004003 reflected both the residents and licensees findings that corrective actions for several Severity Level 2 (and 3) CRs had not always been sufficiently comprehensive to prevent (or reduce the likelihood of) recurrence. As discussed below, the team identified similar findings of missed opportunities for the CAP to promptly resolve problems.

(a) 1A Containment Spray Pump Room Cooler Failures

Introduction:

A Green, self-revealing non-cited violation (NCV) of 10 CFR 50, Appendix B, Criterion XVI, Corrective Action, was identified for failure to identify a significant condition adverse to quality. Specifically, following the July 15, 2003 trip of the 1A containment spray pump room cooler, the licensee failed to identify an existing degraded time delay relay. Consequently, for the period between July 15, 2003, until corrected on May 1, 2004, the degraded condition of the 1A containment spray pump room cooler rendered it vulnerable to run/stop/hot restart scenarios that could be encountered during the response to a large break LOCA.

Description:

On March 23, 2004, during the performance of surveillance test procedure FNP-1-STP-16.1, 1A Containment Spray Pump Quarterly In Service Test, the 1A containment spray pump and its associated room cooler were stopped to facilitate adding oil to the pump. About 1 - 3 minutes after restart of the pump and room cooler, the room cooler tripped. Troubleshooting revealed the thermal overloads for the 1A containment spray pump supply breaker had tripped. The thermal overloads were reset and FNP-1-STP-16.1 was successfully completed. Operations personnel suggested that this event was similar to an event which occurred on July 15, 2003, during the same surveillance test. At the time of the July 2003 event, the 1A containment spray pump room cooler had been running to support painting in the pump room when it was stopped for the quarterly pump test. Approximately 1 - 3 minutes after starting the 1A containment spray pump and room cooler, the room cooler tripped. The thermal overloads were reset twice before FNP-1-STP-16.1 could be successfully completed.

Followup actions to the July 15, 2003 event involved tightening electrical connections and post-maintenance testing of the room cooler, but not in the run/stop/hot restart fashion in which it had failed.

Investigation into the similarity of the two events resulted in troubleshooting efforts on April 30, 2004. These efforts determined that a degraded time delay relay was most likely the cause for both events and Minor Departure 04-2760 was implemented on May 1, 2004, to correct the problem. This time, post-maintenance testing was conducted satisfactorily in the run/stop/hot restart fashion. To assure operability, the 1B containment spray pump room cooler was subsequently tested satisfactorily in the run/stop/hot restart fashion. In addition, Design Change Request (DCR) M04-1-0060 was created to make the thermal overload configuration in the Unit 1 pump room coolers the same as in Unit 2. This design change had been completed on both Unit 1 containment spray pump room coolers and was scheduled to be implemented on the remaining Unit 1 pump room coolers in 2006. Further investigation by the licensee concluded that the root cause evaluation for the July 15, 2003 event was inadequate; resulting in a maintenance preventable functional failure (MPFF) of the 1A containment spray pump room cooler on March 23, 2004. However, the team determined that the degraded condition of the 1A containment spray pump room cooler rendered it vulnerable to run/stop/hot restart scenarios that could be encountered during the response to a large break LOCA. Such scenarios would involve:

(1) a subsequent loss of offsite power and re-sequencing loads on the emergency diesel generators; or

(2) the need to momentarily secure containment spray pumps/room coolers to facilitate the transfer of emergency core cooling systems to the containment sump.

Analysis:

This finding is more than minor because it affects the Barrier Integrity Cornerstone attribute of Barrier Performance and impacted the cornerstone objective in that tripping of the room cooler could result in loss of the 1A containment spray pump safety function due to overheating. This finding is of very low safety significance (Green) because the 1B containment spray pump and room cooler and all containment coolers were available to ensure containment barrier integrity would be maintained in the event of a large break LOCA or containment over pressure challenge. This finding has the cross-cutting aspect of Problem Identification and Resolution in the area of Identification.

Enforcement:

10 CFR 50, Appendix B, Criterion XVI, Corrective Actions, required that measures shall be established to assure that significant conditions adverse to quality are promptly identified. Contrary to the above, following the July 15, 2003 trip of the 1A containment spray pump room cooler the licensee failed to identify a degraded time delay relay. Consequently, a similar run/stop/hot restart trip of the room cooler occurred on March 23, 2004. For the period between July 15, 2003, until corrected on May 1, 2004, the degraded condition rendered the 1A containment spray pump room cooler vulnerable to run/stop/hot restart scenarios that could be encountered during the response to a large break LOCA. Because this finding is of very low safety significance and has been entered into the licensees corrective action program (CR 2005109145), this violation is being treated as an NCV, consistent with Section VI.A of the NRC Enforcement Policy: NCV 05000348/2005008-01, Failure to Identify 1A Containment Spray Pump Room Cooler Degraded Time Delay Relay.

(b) SSPS/7300 Troubleshooting

Introduction:

A Green, NRC-identified NCV of 10 CFR Part 50, Appendix B, Criterion XVI, was identified for failure to take corrective actions to preclude repetition of a significant condition adverse to quality. Specifically, corrective actions taken to develop a SSPS/7300 troubleshooting guideline following a Unit 2 SSPS/7300 troubleshooting-related reactor trip on April 12, 2004, was inadequate to preclude the recurrence of another SSPS/7300 troubleshooting-related event on April 28, 2005.

Description:

On April 11, 2004, Unit 2 tripped due to a fault which unblocked the source range high flux trip. SSPS/7300 troubleshooting resulted in two SSPS cards being replaced and the unit was restarted. However, Unit 2 tripped again on April 12, 2004, due to the same unblocking of the source range high flux trip. Subsequent troubleshooting revealed that a different SSPS card was the source of the problem. The licensee also determined that, as a contributing cause, troubleshooting activities following the first trip did not use a rigorous troubleshooting methodology to identify and validate the specific equipment failure and corrective action. Additionally, no formal guidance for troubleshooting problems in the SSPS/7300 process channels existed.

Therefore, the exact equipment failure was not correctly identified and the problem recurred. Corrective actions to prevent recurrence included development of formal SSPS/7300 troubleshooting guidance.

A similar SSPS/7300 troubleshooting-related event occurred subsequently on April 28, 2005, when annunciators for the 1B Steam Generator Main Steam Line Delta P Alert came into alarm. Based on the control board indications and previous history of failed 7300 cards, the licensee believed that a 7300 card had failed and entered TS 3.3.2, LCO D for an inoperable 7300 channel. The required action for this condition was to place the channel in trip within 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> or be in Mode 3 within 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> and Mode 4 within 18 hours2.083333e-4 days <br />0.005 hours <br />2.97619e-5 weeks <br />6.849e-6 months <br />. After placing the channel in the tripped condition, troubleshooting was begun on the associated 7300 cards to identify the exact failure. The licensee had determined that the 7300 cards were sending the proper signal to SSPS and concluded that the current TS LCO may not be correct. Based on this information, the licensee tested an input relay that was the interface between the 7300 and SSPS circuitry and, on April 29, 2005, it was found to be satisfactory. Consequently, TS 3.3.2, LCO D was exited and the licensee entered TS 3.3.2, LCO C for SSPS "A" Train. The required action for this condition was to restore the train to operable status within 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> or be in Mode 3 within 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br />. Troubleshooting on SSPS was subsequently completed, revealing that a SSPS logic card had failed. After the logic card was replaced, and SSPS tested satisfactorily, the licensee exited the LCO. (Note: The failure to follow TS for an inoperable SSPS logic train was previously dispositioned as NCV 05000348/2005003002.)

The licensee identified a lack of procedural guidance to diagnose an alarm condition as the root cause for the extended amount of time needed to troubleshoot the alarm condition and associated TS concerns. Accordingly, a troubleshooting work order sequence for such annunciator problems was incorporated into the SSPS/7300 troubleshooting guidance.

Analysis:

This finding is more than minor because it affects the Mitigating Systems Cornerstone attribute of equipment performance and adversely impacted the cornerstone objective in that the SSPS/7300 troubleshooting guidance did not provide the necessary steps to facilitate a timely (i.e., within the TS LCO) determination of a SSPS/7300 process channel failure. This finding is of very low safety significance because the B train of SSPS was maintained operable at all times. This finding has the cross-cutting aspect of Problem Identification and Resolution in the area of Corrective Actions.

Enforcement:

10 CFR 50, Appendix B, Criterion XVI, Corrective Actions, required that measures shall be established to assure that significant conditions adverse to quality are corrected to preclude repetition. Contrary to the above, the SSPS/7300 troubleshooting guideline developed as a corrective action for a Unit 2 SSPS/7300 troubleshooting-related reactor trip on April 12, 2004, was inadequate to preclude the occurrence of another SSPS/7300 troubleshooting-related event on April 28, 2005.

Because this finding is of very low safety significance and has been entered into the licensees corrective action program (CR 2005109147), this violation is being treated as a NCV, consistent with Section VI.A of the NRC Enforcement Policy: NCV 05000364/2005008-02, Inadequate Corrective Action Results in Recurrence of a SSPS/7300 Troubleshooting-Related Event.

(c) Radiation Monitor R-11 Failures

Introduction:

A Green, NRC-identified finding (FIN) was identified for untimely resolution of excessive air flow problems on the Unit 1 and Unit 2 Containment Air Particulate Radiation Monitors (R-11). Excessive air flow through the moving filter paper caused the monitor to become inoperable on numerous occasions since 1990. When R-11 was out of service, the ability to detect low-level RCS leakage was degraded.

Description:

After the licensee installed new paper drives in 1990, radiation monitor R-11 experienced frequent paper drive malfunctions and pump trips. The licensee determined that there was too much air flow through the sample lines. The sample air flow for R-11 was originally designed for 10 cubic feet per minute (CFM) and the pumps were sized accordingly. However, the paper drive vendor recommended a flow rate of no more than 5 CFM to avoid paper drive related problems. Due to these problems, radiation monitor R-11 was put on the MR (a)(1) list in 1995.

In order for R-11 to perform its TS function, at least 4 CFM air flow was required.

However, due to uncertainties in the flow measuring device, the flow rate must be set at 6 CFM or greater to ensure that the TS required 4 CFM passes through the filter paper.

On August 8, 1996, DCR 96-1-9059 was submitted to install a bypass line to reduce the air flow through the filter paper to 6 CFM with the remaining 4 CFM bypassing the paper drive/detector assembly. No analysis was performed to determine whether the flow rate upstream of the detector could be reduced below the design rate of 10 CFM. The design change was completed in December 1997 but, frequent pump trips and paper drive problems due to excessive flow rate continued to be a problem. Also, with the new bypass line installed, small fluctuations in pressure caused Hi/Lo air flow alarms. Root Cause Investigation 2-98-338/1-98-328, Request for Engineering Assistance (REA)99-2100, and REA 99-2121 were completed to evaluate R-11 pump-related problems.

The licensee concluded that more man-power intensive preventive maintenance tasks (PMs) were required to keep R-11 functional (e.g., more frequent checks on pump drive belts and filter paper status, stricter adherence to vendor lube requirements, etc.). The new PMs were effective in addressing the symptoms and R-11 was removed from the Maintenance Rule (a)(1) list in late 2000. However, because the licensee did not develop any corrective actions to address the underlying problem of excessive air flow, the team concluded that the new PMs were effectively a work-around.

Beginning in 2003, problems related to excessive air flow again became an issue as documented in numerous CRs including 2003002541, 2004000192, 2004101110, 2005101978, 2005012025, 2005102065, 2005102457, 2005106984, 2005017050, 2005107120, and 2005107076. In August 2004, R-11 was put back on the MR (a)(1)list. In August 2005, Request for Engineering Review C050882501 was submitted to modify the system. This modification would eliminate the bypass line, reduce the capacity of the sample pumps flow from 6 CFM to 2-3 CFM, and replace the flow measurement device with a more accurate automated mass-flowmeter. These modifications, which appeared to be an adequate solution, are scheduled to be implemented in 2006.

Analysis:

The team determined that the R-11 air flow related problems are a performance deficiency in that the resultant impact to the instruments ability to perform its TS required function was reasonably within the licensees ability to correct in a timely manner. This finding is more than minor because it is associated with the RCS Equipment and Barrier Performance Attribute of the Barrier Integrity Cornerstone and adversely affects the cornerstone objective in that the ability to detect low-level RCS leakage that may indicate pressure boundary degradation was reduced. This finding could not be evaluated using the Significance Determination Process (SDP) in accordance with IMC 0609 because the SDP for the RCS barrier only applied to a degraded barrier; not the ability to detect a degraded barrier. Therefore, this finding was reviewed by the regional management and determined to be of very low safety significance (Green) because alternate methods of detecting low-level RCS leakage were available when R-11 has been out of service. This finding has the cross-cutting aspect of Problem Identification and Resolution in the area of Resolution.

Enforcement:

No violation of TS or other NRC requirements occurred. This finding has been entered into the licensees corrective action program (CR 2005109190) and is identified as Finding (FIN) 05000348,364/2005008-03, Untimely Resolution of Flow Problems on Radiation Monitor R-11.

d. Assessment of Safety-Conscious Work Environment (SCWE)

(1) Inspection Scope The team conducted interviews with randomly selected members of the plant staff, including operations, maintenance, engineering, health physics, and emergency preparedness personnel, to develop a general perspective of the SWCE at the site and the willingness of personnel to use the CAP and the employee concerns program (ECP). The interviews were also to determine if any conditions existed that would cause employees to be reluctant to raise safety concerns. The team also reviewed the licensees ECP, which provides an alternate method to the CAP for employees to raise concerns and remain anonymous. The team interviewed the ECP Coordinator and reviewed a select number of ECP reports completed since August 2003 to verify that concerns were being properly reviewed and that identified deficiencies were being resolved in accordance with the SNC Concerns Program Procedure, Revision 8.

(2) Assessment The team concluded that licensee management emphasized the need for all employees to identify and report problems using the appropriate methods established within the administrative programs, including the CAP and ECP. These methods were readily accessible to all employees. Licensee management encouraged employees to promptly identify nonconforming conditions. Based on discussions conducted with a sample of plant employees from various departments, the team determined that the site staff felt free to raise issues and felt that management wanted issues placed into the CAP for resolution. The staff members also believed that feedback was good when using the CAP and the ECP, and that they were kept up to date on identified issues. The team noted that, for the ECP files they had reviewed, CRs were initiated in the CAP for any substantiated condition adverse to quality that had been identified in the file. The team also did not identify any reluctance to report safety concerns.

4OA6 Management Meetings Including Exit

The team presented the inspection results to Mr. Todd Youngblood and other members of licensee management on August 25, 2005, who acknowledged the findings. The team also confirmed that proprietary information was not provided or examined during the inspection.

ATTACHMENT:

SUPPLEMENTAL INFORMATION

KEY POINTS OF CONTACT

Licensee personnel

W. Bayne, Performance Analysis Supervisor

S. Chestnut, Engineering Support Manager

P. Harlos, Health Physics Manager

J. Hunter, Operations Support

D. Lisenby, Engineering Supervisor

R. Wells, Operations Outage Support

T. Youngblood, Assistant General Manager - Plant Support

NRC personnel

C. Patterson, Senior Resident Inspector-Farley

P. Xavier Bellarmine, Reactor Inspector

LIST OF ITEMS

Opened and Closed

05000348/2005008-01 NCV Failure to Identify 1A Containment Spray Pump Room Cooler Degraded Time Delay Relay.

(Section 4OA2c.(2)(a))

05000364/2005008-02 NCV Inadequate Corrective Action Results in Recurrence of a SSPS/7300 Troubleshooting-

Related Event (Section 4OA2c. (2)(b))

05000348,364/2005008-03 FIN Untimely Resolution of Flow Problems on Radiation Monitor R-11 (Section 4OA2c.(2)(c))