IR 05000454/2009008

IR 05000454-09-008 and 05000455-09-008 on 08/10/2009 - 08/28/2009; Byron Station, Units 1 and 2; Identification and Resolution of Problems

ML092880975
Person / Time
Site:	Byron
Issue date:	10/15/2009
From:	Richard Skokowski Region 3 Branch 3
To:	Pardee C Exelon Generation Co, Exelon Nuclear
References
FOIA/PA-2010-0209 IR-09-008
Download: ML092880975 (29)

Text

tober 15, 2009

SUBJECT:

BYRON STATION, UNIT 1 & 2 NRC PROBLEM IDENTIFICATION AND RESOLUTION INSPECTION REPORT 05000454/2009008; 0500455/2009008

Dear Mr. Pardee:

On September 1, 2009, the U.S. Nuclear Regulatory Commission (NRC) completed an inspection at your Byron Station. The enclosed inspection report documents the inspection results, which were discussed on September 1, 2009, with Mr. B. Adams and other members of your staff.

The inspection examined activities conducted under your license as they relate to safety and compliance with the Commission=s rules and regulations and with the conditions of your license.

The inspectors reviewed selected procedures and records, observed activities, and interviewed personnel.

On the basis of the samples selected for review, the team concluded that in general, problems were properly identified, evaluated, and corrected. There was one NRC-identified finding of very low safety significance associated with untimely corrective action to restore fire protection equipment obstruction. The finding was determined to be a violation of NRC requirements.

However, because of its 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 VI.A.1 of the NRC Enforcement Policy.

In addition, several examples of minor problems were identified, including untimely condition report evaluations, and corrective actions that were ineffectively tracked or had not occurred.

If you contest the subject or severity of a Non-Cited Violation, 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 Byron 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 III, and the NRC Resident Inspector at Byron Station. The information you provide will be considered in accordance with Inspection Manual Chapter 0305. 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 (PARS) component of the 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/

Richard A. Skokowski, Chief Branch 3 Division of Reactor Projects Docket Nos. 50-454; 50-455 License Nos. NPF-37; NPF-66

Enclosure:

Inspection Report No. 05000454/2009008 and 05000455/2009008 w/Attachment: Supplemental Information

REGION III==

Docket Nos: 50-454; 50-455 License Nos: NPF-37; NPF-66 Report Nos: 05000454/2009008 and 05000455/2009008 Licensee: Exelon Generation Company, LLC Facility: Byron Station, Units 1 and 2 Location: Byron, IL Dates: August 10, 2009, through September 1, 2009 Team Leader: R. Ng, Project Engineer Inspectors: J. Robbins, Resident Inspector G. ODwyer, Reactor Inspector E. Coffman, Reactor Engineer C. Thompson, Resident Inspector, Illinois Emergency Management Agency Approved by: R. Skokowski, Chief Branch 3 Division of Reactor Projects Enclosure

SUMMARY OF FINDINGS

IR 05000454/2009008; 05000455/2009008; 08/10/2009 - 08/28/2009; Byron Station, Units 1 and 2; Identification and Resolution of Problems.

This inspection was conducted with region-based inspectors, the NRC Resident Inspector at the Byron Station and the onsite Illinois Emergency Management Agency (IEMA) inspector. 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.

Identification and Resolution of Problems The inspectors concluded that the licensees corrective action program (CAP) in general was effective in identifying, evaluating and correcting issues at the site. The licensee had a low threshold for identifying issues and entering them into the CAP. Overall, the issues were properly prioritized and evaluated based on plant risk and uncertainty. Corrective actions, when specified, were generally implemented in a timely manner, commensurate with their safety consequences. The use of operating experience was found to be effective and was integrated into daily activities. In addition, the licensees self-assessments, audits and effectiveness reviews were thorough and effective in identifying site performance deficiencies, programmatic concerns and improvement opportunities. On the basis of the interviews conducted, site personnel were free to raise safety concerns through the established processes.

There was one Green Non-cited Violation (NCV) identified by the team during this inspection.

The finding was related to the licensees failure to perform timely corrective actions for a previously identified violation.

NRC-Identified

and Self-Revealed Findings

Cornerstone: Initiating Events

• Green: The inspectors identified a Green NCV of Byron License Condition 2.C.(6)for Unit 1 for failure to take timely corrective actions as described in the Fire Protection Program to address a previously issued NCV regarding sprinkler obstruction by scaffolding in the 1A diesel oil storage tank room. Specifically, the licensee did not fully evaluate the issue before reinstalling a different type of scaffold planks. After the licensee concluded the plank was not acceptable, there was no full extend of condition walkdown until 5 months later and no modification to the scaffold until the inspectors identified the condition in August 2009. The initial violation was originally identified by NRC inspectors in April 2008.

This finding is more than minor because it was associated with the external factor attribute of the Initiating Events (IE) cornerstone and affected the cornerstone objective to limit the likelihood of those events that upset plant stability and challenge critical safety functions during shutdown as well as power operations. The finding is of very low safety significance because it has a low degradation rating as only one out of 11 sprinklers in the room was obstructed and there was another functional head within 10 feet of the combustible concern. This finding has a cross-cutting aspect in the area of Human Performance for Resources (H.2(a)) because the licensee failed to minimize long standing equipment issue. The licensee immediately removed the scaffold obstruction and entered this issue into the CAP as Issue Report (IR) 953448. (Section 4OA2.3)

Licensee-Identified Violations

None.

REPORT DETAILS

4OA2 Problem Identification and Resolution

This inspection constitutes one biennial sample of problem identification and resolution as defined by Inspection Procedure 71152. Documents reviewed were listed at the to this report.

.1 Assessment of the Corrective Action Program (CAP) Effectiveness

a. Inspection Scope

The inspectors reviewed the procedures and processes that describe Exelons CAP at Byron Station to ensure, in part, that the station had an adequate program for meeting 10 CFR 50, Appendix B, Criterion XVI, Corrective Action, requirements. The inspectors observed and evaluated the effectiveness of CAP meetings such as Station Ownership Committee and Management Review Committee (MRC). Selected licensee personnel were interviewed to determine their understanding and their involvement of the CAP.

The inspectors reviewed selected issue reports across all seven cornerstones of safety to determine if problems were being properly identified and entered into the CAP. The majority of the risk-informed sample of IRs was issued since the last NRC biennial Problem Identification and Resolution (PI&R) inspection conducted in July of 2007. The inspectors also reviewed selected issues that were more than 5 years old.

The inspectors assessed the licensees characterization and evaluation of the issues and examined the assigned corrective actions. This review encompassed the full range of safety significances and evaluation classes such as root cause evaluations, apparent cause evaluations, and workgroup evaluations. The inspectors assessed the scope and depth of the licensees evaluations. For significant conditions adverse to quality, the inspectors evaluated the licensees corrective actions to prevent recurrence and for lower safety significance issue, the inspectors reviewed the corrective actions to determine if they were implemented in a timely manner commensurate with their safety significance.

The inspectors selected the instrument air system (IA) to review in detail since IA was a non-safety related system that was risk significant. The review was to determine whether the licensee was properly monitoring and evaluating the performance of this system through effective implementation of station monitoring programs. The inspectors interviewed the system engineer of the applicable system, reviewed numerous issue reports, and reviewed root cause evaluations. A 5-year review of instrument air issues was undertaken to assess the licensees efforts in monitoring for system degradation due to aging aspects.

The inspectors reviewed the licensees CAP trend analysis and independently performed a five-year review of the human performance trend and Maintenance Rule (a)(1) system action plans to determine if issues were tracked to identify adverse trend or repetitive issues.

The inspectors examined the results of the two self-assessments of the CAP completed during the review period. The results of the audits were compared to the self-revealed and NRC identified findings. The inspectors also reviewed the corrective actions associated with previously identified NCVs and findings to determine whether the station properly evaluated and resolved those issues. The inspectors performed walkdowns to verify the resolution of the issues.

The inspectors conducted a targeted review to evaluate the completion and effectiveness of the stations corrective actions taken to address weaknesses identified during the 2009 NRC 95001 supplemental inspection involving a White violation related to degraded essential service water riser piping.

b. Assessment

(1) Identification of Issues The inspectors concluded that, in general, the station continued to identify issues at a low threshold by entering them into the CAP. The inspectors determined that the station was appropriately screening issues from both NRC and industry operating experience (OE) at an appropriate level and entering them into the CAP when applicable to the station. The inspectors also noted that deficiencies were identified by external organizations (including the NRC) that had not been previously identified by licensee personnel.

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 corrective actions were ineffective or were inappropriately closed.

Observations:

Human Performance Related Trend Overall, the sites performance continues to trend in a positive direction. The stations composite error rate trend data for errors per 10,000 hours0 days <br />0 hours <br />0 weeks <br />0 months <br /> worked continued to move toward the sites established goal of four. The 6 month rolling average error rate has been reduced from about 5.5 errors per 10,000 hours0 days <br />0 hours <br />0 weeks <br />0 months <br /> in July 2008 to about 4.5 errors per 10,000 hours0 days <br />0 hours <br />0 weeks <br />0 months <br /> in August 2009. The positive performance trend of the operations, maintenance, and engineering departments are all contributing to the overall site performance improvement.

One of the programs that the licensee used to measure/indicate plant performance is the Station Event-Free Clock Program. This program provides an indicator that is a reflection of human performance at the site. Specifically, a clock reset is assessed when an issue is determined to be associated with inadequate human performance

[example: failure to write an issue report when required] or inadequate technical human performance [example: work product deficiencies from engineering]. Therefore, a low number of clock resets is indicative of a site with human performance levels in excess of the standard. Although the site did revise the implementing procedure for the Station Event-Free Clock Program during the month of August 2008, the procedural changes do not appear to have altered the program performance since there were approximately the same numbers of resets during the last 5 months as in the previous 7 months.

Station Event-Free Clock resets are cumulative and are counted over the calendar year.

In 2004, the station had 144 departmental clock resets. The number decreased over the years to 57 departmental clock resets in 2007. In 2008, the number increased slightly to 68. As of July of 2009, there were 16 departmental clock resets.

Configuration Control is another measure used by the site to measure/indicate plant performance. This term refers to a sites ability to manage equipment manipulations in such a way that the state of a given piece of equipment can be known by the record of its last manipulation. During the calendar year 2008 the operation department was responsible for 12 configuration control events; equipment was discovered in a state/alignment that was not in agreement with its expected state/alignment. As of July 2009, there have been three configuration control events attributed to operations.

During the calendar year 2008, the maintenance department was responsible for 6 configuration control events. As of July 2009, there have been no configuration control events attributed to the conduct of maintenance.

One of the programs the engineering department uses to measure/indicate plant performance is System Health Monitoring program. This indicator is a reflection of the sites ability to effectively maintain plant equipment; to detect and correct changes in equipment reliability or degrading material conditions. System Health ratings are:

Excellent (Green), Acceptable (White), Marginal (Yellow), and Unacceptable (Red).

During the third quarter of calendar year 2008, nine systems were rated marginal or unacceptable. Specifically, seven systems were rated as Red and two systems were rated as Yellow. As of July 2009, there is one system that is rated Red and no systems that are rated Yellow.

Potential Failure of all the Emergency Diesel Generators (EDG) for Both Units 1 and 2 during a Loss of Offsite Power Event

Introduction:

The inspectors identified an unresolved item regarding the EDG Jacket Water (JW) thermostatic 5043 control valves (5043 valves).

Description:

As part of the review of the root cause evaluation for the partial loss of instrument air for both units that occurred August 18, 2007, the inspectors reviewed piping and instrumentation diagrams (P&IDs) to identify equipment that would fail to operate after a loss of instrument air. The inspectors identified that a loss of offsite power would cause a loss of instrument air and would cause the EDG JW thermostatic control valve 5043 valve on each EDG to fail open. The EDG Jacket Water Cooling System is a closed system and is cooled by the Essential Service Water System (SX)through the JW heat exchanger (HX). The system keeps engine warm to promote rapid starts in standby and removes heat from engine during EDG operation.

After a design basis accident, the EDGs might be operated in unloaded condition for short periods of time during swapping of loads or starting and stopping of EDGs. As a result the system would not be able to control the amount of JW going to the JW HX with a loss of instrument air. The Updated Final Safety Analysis Report stated that the SX system temperature was designed to range from 40 to 100 degrees Fahrenheit. The inspectors were concerned that during low SX temperature periods (e.g. winter months),these failed open valves might allow excessive cooling to the JW system of EDG and adversely affect the operability of the EDGs and the ability to perform the required safety functions. The licensee initiated IR 958882 to document this NRC concern and perform a thorough evaluation to demonstrate that the EDGs will adequately perform the required safety functions.

In addition, Section 6 of the licensees 10 CFR 50.59 Safety Evaluation 6G-98-0275 for a previously replaced 5053 valve controller stated that Failure of the original or replacement controller may affect the quick start of the diesel as the engine is not pre-warmed. The licensee stated that the evaluation required by the IR would demonstrate that the statement in the Safety Evaluation was not applicable.

Pending the licensees submittal of the evaluation and calculation to the NRC for review to resolve this issue, this item will be tracked as an unresolved item (URI 05000454/2009008-01; URI 05000455/2009008-01).

(2) Prioritization and Evaluation of Issues The inspectors concluded that the station was generally effective at prioritizing and evaluating issues commensurate with the safety significance of the identified problem.

The inspectors determined that the MRC CAP review meeting was generally thorough and maintained a high standard for approving action. However, low safety significance issues only required supervisor approval for evaluation extension. The inspectors identified that a number of procedure related evaluations were granted extensions without reason for extension documented. Specifically:

• IR 727830 identified in January 2008 that the statement in Procedure BOA ELECT-2, Loss of AC Power, related to auto-makeup of the Volume Control Tank might not be accurate. Engineering was assigned to evaluate this issue but the due date was now extended to December 2009.

• IR 739569 identified in February 2008 that the simplified drawing in Procedure 0BOA SEC-4, Loss of Instrument Air was not accurate. However, the procedure was not revised until June 2009.

The inspectors determined that these issues were minor because operators had other means to obtain the needed information. The licensee entered this issue into the CAP as IR 968120.

The inspectors determined that the licensee was generally effective at evaluating equipment functionality requirements after a degraded or non-conforming issue was identified. The inspectors reviewed Maintenance Rule action plans and issue reports associated with systems returning to (a)(1) again after the licensee had successfully completed the (a)(1) action plans and had previously returned the systems to (a)(2)within the last 5 years. The inspectors determined that issues were tracked to identify adverse trends and actions assigned to correct repetitive issues when applicable.

Observation:

Auxiliary Feedwater Pump Gearbox Vibration On April 28, 2008, the licensee performed its first In-Service Test under full flow condition on the Unit 1 Train B Auxiliary Feedwater Pump. A change in test conditions was necessitated by a recent change in ASME code. Most of the data collected during this test were used by the licensee in their in-service testing and trending programs to identify changes in pump performance over time. In addition to the ASME required data points, the licensee also collected additional data that were used to evaluate the preventative maintenance program. In this instance, the extra vibration data points were recorded for the gearbox that is located between the diesel and the pump. Some of the data points recorded were higher than their expected range; each of these points measured horizontal acceleration. Since these data points were not part of the required ASME data evaluation requirements, the pump passed the surveillance. The data was passed to the appropriate system engineer to determine the cause and impact of these high vibrations.

Since this test was being conducted under different conditions, the system engineer needed to determine if this behavior was expected for the new test conditions. There was also a possibility that there was an issue with the data collection equipment that was affecting the horizontal measurement data. Decisions were made to collect data from the Unit 2 Auxiliary Feedwater Pump during its full flow test, to collect information from a site with similar equipment and to collect a second set of data from the Unit 1 Auxiliary Feedwater Pump. The results of the data collection allowed the licensee to determine that the recorded vibrations were not expected to occur as a result of the new test conditions. Unfortunately, three quarters passed while this data was being collected.

In March of 2009, the licensee contacted the vendor and requested support to diagnose and correct the problem. Testing identified the cause of the high vibrations as a combination of alignment issues and a resonance condition that existed between the gearbox and the pump running frequency. Adjustments to the alignment of the gearbox and pump were made. A temporary modification was installed to address the resonance issue. A successful full flow test was run after these changes had been implemented.

A past operability determination was made by the licensee to assess the impact of the high vibrations on the equipment under licensing bases conditions. The licensee determined that the pump would have performed as designed upon demand. The licensee acknowledged that the data collection and the past operability determination could have been performed in a more expeditiously manner to validate the operability of this risk significance system.

(3) Effectiveness of Corrective Action The inspectors concluded that corrective actions for identified deficiencies were generally timely and adequately implemented, commensurate with their safety significance. Problems identified using a root or apparent cause methodologies were resolved in accordance with program and NRC requirements. The inspectors also concluded that sampled corrective actions assignments for selected NRC documented violations were generally effective and timely. However the inspectors did notice a number of untimely corrective actions as described below.

The inspectors determined that the stations corrective actions designed to prevent recurrence (CAPRs) were generally comprehensive, thorough, and timely. The inspectors did notice two CAPRs were in the order of 1500 days old. Specifically, the CAPRs to modify the non-safety related turbine driven feedwater pumps had not been completed since they were assigned in 2004. This modification would resolve an oil pressure problem that caused a reactor trip in 2004. The delay was due to scope change and subsequent cancellation of the scope change. The inspectors determined that this issue was minor since the issue would only potentially cause a reactor trip and the licensee had not experienced the same oil pressure issue since 2004.

The inspectors assessed selected effectiveness reviews for the root cause evaluation to address the SX piping degradation that resulted in a WHITE violation. The inspectors determined that corrective actions were properly implemented and the licensee is addressing external piping corrosion at the plant.

Observations:

a. Instrument Air System had Untimely Corrective Actions for Excessive Moisture Intrusions The inspectors performed a review of the high number of issue reports associated with the Instrument Air System (IA). The majority of these IRs were initiated by operations personnel since July 2004. These IRs documented that there were inadequate number of drains in the IA and Service Air System (SA) headers and that there were accumulation of excessive water in the header piping for the IA and SA systems. The IRs also documented the burden on operators to repeatedly drain all the IA and SA headers of excessive water up to three times a day and that drain valves were becoming plugged sometimes, allowing no water to drain until repaired. Note that, the SA system supplies air to the IA system through the IA dryers at Byron Station.

The corrective actions were primarily to increase operator blowdowns and repair the plugged drain valves. IR 464402 was initiated in March 2006 to document excessive moisture in the SA system. One of the corrective actions was to modify the system to add more drains to the IA/SA headers. This was the same corrective actions that engineering personnel had previously recommended. However, the modification was rejected by the Plant Health Committee on April 12, 2006.

On August 18, 2007, both units experienced a partial loss of instrument air. Alarms were received in the main control room for low Net Positive Suction Head (NPSH) for all the Main Feedwater Pumps for both Units 1 and 2. Also the standby Condensate and Condensate Booster Pumps automatically started due to the low NPSH. Main Control Room instruments indicated that the IA header fell to as low as 80 psig and this almost tripped both units offline. The cause of the partial loss of instrument air was determined to be moisture intrusion from the SA system that plugged the IA dryers.

One of the licensees corrective actions for this event was to install drain traps for five drain valves in the IA system and three drain valves in the SA system. These corrective actions are untimely in that the licensee had not adequately implemented these actions as of the end of the inspection period. The due date for these actions has been extended from December 2008 to April 2010. The failure to adequately implement these actions has resulted in shiftly blowdown of the low point drains to keep the IA system operational. Nonetheless, these shiftly actions were properly classified as an Operator Challenge (OC 298) in accordance with the licensees Operators Workaround Program on March 30, 2008. The OC 298 document stated that, This issue impacts operators extensively by requiring excessive time spent on rounds to blow down drops [drain valves].

The inspectors assessed the above mentioned instrument air problems as captured in the licensees corrective action program, and determined that there were no incidences severe enough to challenge plant safety systems. Therefore, the issue was not a significant condition adverse to quality and no violations of NRC requirements occurred.

In addition, the inspectors reviewed the licensees OE evaluation of NRC Information Notice 2008-06 related to loss of instrument air due to failure of a soldered connection.

The licensee had established structural integrity acceptable criteria for solder joints to protect them from catastrophic failure. However, a detailed inspection plan had not been developed. Because there were no failure of the IA solder joint at Byron Station since the completion of the evaluation, the licensees decision not to timely implement actions from the OE evaluations is only a weakness and not a violation of NRC requirements.

b. Untimely Corrective Actions for Sprinkler Obstruction in the 1A DOST Room

Introduction:

The inspectors identified a Green NCV of Byron Operating License Condition 2.C.(6) for Unit 1 for failure to take timely corrective actions as described in the Fire Protection Program to address a previously issued NCV regarding sprinkler obstruction by scaffolding in the 1A diesel oil storage tank room (DOST).

Descriptions: NCV 05000454/2008003-01 was issued for the failure to comply with the spacing standard for sprinkler system of the Fire Protection Program. Specifically in April 2008, NRC inspectors identified that the licensee had installed a permanent scaffold with solid decking material underneath a fire suppression sprinkler and next to a working platform. This permanent scaffold, B-4855, in conjunction with the working platform, obstructed a major portion of the spray pattern of one of the foam based fire suppression sprinklers to a portion of the floor area in the 1A DOST room. The licensee entered this issue into their CAP as IR 770364 and removed the planks subsequently.

Since the scaffold was needed to refill the diesel generator fuel oil tank from time to time, a mechanical maintenance supervisor wrote IR 779116 to investigate options.

Maintenance planning was assigned to work with the fire protection engineer and operations to evaluate the options. They concluded that grating planks would meet the fire protections requirements and installed the gratings on June 11, 2008. However, the scaffold tracking log was not updated to reflect the installation of the grating as required by Procedure MA-AA-716-025, Scaffold Installation, Modification, and Removal Request Process, Revision 5. During the IR review at that time, the MRC assessed the assigned actions and resolution and had no comments. Also at the time, Engineering had no formal documented position regarding the use of grating as a substitute and was in discussion with the NRC on the applicability of spacing requirement. The licensee was working to change the corporate procedure to allow the use of grating.

During the scaffold walk down for the Byron Unit 2 refueling outage in August 2008, the fire marshal identified that there were numerous scaffoldings in the turbine building built in sprinkled area. However, the auxiliary building was not walked down at that time.

On August 6, 2008, the site fire protection program engineer wrote IR 804282 and recommended that the foam system for the 1A DOST room be considered operable with the solid scaffolding deck in place. After further discussion with the NRC, in November 5, 2008, the licensee determined that the spacing requirement was applicable to the station. On December 5, 2008, the licensee determined that the use of grating for plank materials was not acceptable and the corporate procedure would not be revised to allow for grating use.

On April 29, 2009, the licensee completed an extent of condition walkdown of the site to identify all the impair sprinkler locations. Fire protection impairment permits were issued to ensure compensatory actions were in place for the impaired sprinklers. However, the licensee did not walk down the 1A DOST during this evolution.

On August 11, 2009, the inspectors walked down 1A DOST room as part of the NCV corrective action reviewed and identified that grating planks were installed on the Permanent Scaffolding B-4855, which again obstructed the sprinkler coverage area.

The inspectors questioned the licensee about this scaffolding and discovered that the licensee did not recognize that Permanent Scaffolding B-4855 was in operational status because the tracking log was incorrect. The inspectors also noted that although a plan to modify the scaffoldings was initiated in May 2009, the work was not scheduled to complete until after the refueling outage in the September 2009.

The licensee immediately removed the grating planks and entered this issue into the CAP as IR 953448.

Analysis:

The inspectors determined that the licensees failure to promptly correct the sprinkler obstructions was a performance deficiency that warranted a significance determination. The inspector concluded that the issue was greater than minor in accordance with IMC 0612, Appendix B, Issue Disposition Screening. Specifically, it was associated with the external factor attribute of the Initiating Events cornerstone and affected the cornerstone objective to limit the likelihood of those events that upset plant stability and challenge critical safety functions during shutdown as well as power operations.

The inspectors determined that the finding could be evaluated using the SDP in accordance with IMC 0609, Appendix F, Fire Protection Significance Determination Process, because it was associated with fire protection defense-in-depth strategies involving suppression system. The inspectors determined that the finding related to the 1A DOST room had a low degradation rating since only 1 out of 11 sprinklers in the room was obstructed and there was another functional head within ten feet of the combustible concern. In addition, other aspects of the system complied with NFPA code. The inspectors determined that the obstructions for the other areas, such as those in the turbine building, had no impact to safety shutdown analysis and screened as minor violations. Therefore the finding was determined to be of very low safety significance (Green).

This finding has a cross-cutting aspect in the area of Human Performance for Resource (H.2(a)) because the licensee failed to minimize long term equipment issue by not correcting fire protection equipment deficiencies in a timely manner.

Enforcement:

Byron Unit 1 Operating License, Condition 2.C.(6) states, in part, that the licensee shall implement and maintain in effect all provisions of the approved Fire Protection Program as described in the licensees Fire Protection Report. Section 3.4.h of the Fire Protection Report states that measures should be established to ensure that conditions adverse to fire protection are promptly identified, reported and corrected.

Contrary to the above, sprinkler obstructions, such as by Permanent Scaffold B-4855 in the 1A DOST room, were not promptly identified, and corrected after the licensee determined that grating plank was not acceptable per the NFPA 13 code in December 2008. Because this violation was of very low safety significance and because it was entered into the licensees CAP, this violation is being treated as a NCV, consistent with Section VI.A.1 of the NRC enforcement policy.

(NCV 05000454/2009008-02)

.2 Assessment of the Use of Operating Experience

a. Inspection Scope

The inspectors reviewed the licensees implementation of the facilitys OE program.

Specifically, the inspectors reviewed implementing OE program procedures, completed evaluations of OE issues and events, and selected 2007, 2008 and 2009 monthly assessments of the OE composite performance indicators. The inspectors also attended CAP meetings to observe the use of OE information. 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 effective and timely implemented.

b. Assessment The inspectors concluded that the station appropriately considered industry and NRC OE information for applicability, and used the information for corrective and preventative actions to identify and prevent similar issues. The inspectors assessed that OE was appropriately applied and lessons learned were communicated and incorporated into plant operations. In particular, OE information was discussed during Plan of the Day meetings and also incorporated into the work management process as part of the pre-job briefs. The inspectors also observed that Exelon fleet internal OE and industry OE were discussed by licensee staff to support review activities and CAP investigations.

Findings No findings of significance were identified.

.3 Assessment of Self-Assessments and Audits

a. Inspection Scope

The inspectors reviewed selected focused area self-assessments (FASA), check-in self-assessments, root cause effectiveness reviews, and Nuclear Oversight (NOS)audits. The inspectors evaluated whether these audits and self-assessments were being effectively managed, were adequately covering the subject areas, and were properly capturing identified issues in the CAP. In addition, the inspectors also interviewed licensee personnel regarding the implementation of the audit and self-assessment programs.

b. Assessment The inspectors concluded that self-assessments and audits were typically accurate, thorough, and effective at identifying issues and enhancement opportunities at an appropriate threshold level. The inspectors concluded that these audits and self-assessments were completed by personnel knowledgeable in the subject area. In many cases, these self-assessments and audits had identified numerous issues that were not previously recognized by the station. For example, NOS has identified that there was no CAPR for one of the root causes for the SX piping degradation root cause report. It was because another CAPR from the same report addressed this cause; however, it was not documented as such. Therefore, no violations of NRC requirements occurred. However, since the root cause report was reviewed by numerous licensees technical and management staff, this oversight was particularly weak.

Findings No findings of significance were identified.

.4 Assessment of Safety Conscious Work Environment (SCWE)

a. Inspection Scope

The inspectors interviewed selected members of the Byron Station personnel to determine if there were any impediments of a SCWE. In addition, the inspectors discussed the implementation of the Employee Concerns Program (ECP) with the ECP coordinators, and reviewed 2007 - 2009 ECP activities to identify any emergent issues or potential trends. In addition, the inspectors assessed the licensees SCWE through the reviews of the facilitys ECP implementing procedures, discussions with coordinators of the ECP, interviews with personnel from various departments, and reviews of IRs.

The licensees programs to publicize the CAP and ECP programs were also reviewed.

b. Assessment The inspectors determined that the conditions at the Byron Station were conducive to identifying issues. The staff was aware of and generally familiar with the CAP and other station processes, including the ECP, through which concerns could be raised. A number of craft personnel indicated that they did not personally enter issues into the CAP. Instead, their preferred method was to notify supervisors of the issues and had the supervisors enter the issues into the CAP. The inspectors determined that this observation was not a significant concern since the personnel interviewed stated that they were willing to voice issues to their management and/or ask another employee to write the IR for them. Several employees mentioned that they would like face to face feedback after writing IRs and that many IRs were closed to trending. All employees interviewed noted that any safety issue could be freely communicated to supervision and safety significance issues were being corrected. The inspectors determined that although no related regulatory requirement exists, the station could strengthen this area of the CAP by ensuring all station personnel had an adequate working knowledge of entering issues into the CAP and receive proper feedback for issue written.

In addition, a review of the types of issues in the ECP indicated that site personnel were appropriately using the CAP and ECP to identify issues. Note that the site does not have a formal anonymous process for issue identification. Anonymous issues were normally received by or referred to the ECP and tracked under the ECP. The ECP coordinator would enter the issue into CAP when appropriate.

Findings No findings of significance were identified.

4OA6 Management Meetings

Exit Meeting Summary

On September 1, 2009, the inspectors presented the inspection results to Mr. B. Adams, and other members of the licensee staff. The licensee acknowledged the issues presented. The inspectors confirmed that none of the potential report input discussed was considered proprietary.

ATTACHMENT:

SUPPLEMENTAL INFORMATION

KEY POINTS OF CONTACT

Licensee

B. Adams, Plant Manager

L. Bogue, Training Manager

C. Gayheart, Operations Director

S. Greenlee, Engineering Director

D. Gudger, Regulatory Assurance Manager

E. Hernandez, Senior Manager Plant Engineering

B. Spahr, Maintenance Director

D. Thompson, Radiation Protection Manager

P. Woessner, Site Correction Action Program Manager

B. Youman, Work Management Director

C. Keller, Nuclear Oversight

NRC

R. Skokowski, Branch Chief

LIST OF ITEMS

Opened

05000454/2009008-01 URI Potential Failure of all the Emergency Diesel

05000455/2009008-01 Generators (EDG) for Both Units 1 and 2 during a Loss of Offsite Power Event

05000454/2009008-02 NCV Untimely Corrective Actions for Sprinkler Obstructions

Closed

05000454/2009008-02 NCV Untimely Corrective Actions for Sprinkler Obstructions Attachment