IR 05000461/2007007

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May 1, 2007

Mr. Christopher M. CranePresident and Chief Nuclear Officer Exelon Nuclear Exelon Generation Company, LLC 4300 Winfield Road Warrenville, IL 60555

SUBJECT: CLINTON POWER STATIONNRC PROBLEM IDENTIFICATION AND RESOLUTION INSPECTION REPORT 05000461/2007007

Dear Mr. Crane:

On March 23, 2007, the U.S. Nuclear Regulatory Commission (NRC) completed aninspection of problem identification and resolution at your Clinton Power Station. The enclosed inspection report documents the inspection findings which were discussed on March 23, 2007, with Mr. Kearney and other members of your staff.This inspection was an examination of activities conducted under your license as theyrelate to the identification and resolution of problems, compliance with the Commission's rules and regulations and with the conditions of your operating license. Within these areas, the inspection involved selected examination of procedures and representative records, observations of activities, and interviews with personnel. On the basis of the sample selected for review, the team concluded that, in general,problems were properly identified, evaluated, and corrected. One finding of very low safety significance (Green) was identified during this inspection. The finding involved the impropersecuring of radiation protection stanchions in containment within the suppression pool swellzone. This finding was also determined to be a violation of NRC requirements. However,because of its very low safety significance and because it has been entered into your corrective action program, the NRC is treating this finding as a non-cited violation (NCV), in accordance with Section VI.A.1 of the NRC's Enforcement Policy. If you contest the subject or severity of an NCV in this report, you should provide a responsewith the basis for your denial, within 30 days of the date of this inspection report, to the U.S. Nuclear Regulatory Commission, ATTN: Document Control Desk, Washington DC 20555-0001, with copies to the Regional Administrator, Region III; the Director, Office ofEnforcement, U.S. Nuclear Regulatory Commission, Washington, DC 20555-0001; and the NRC Resident Inspector office at the Clinton Power Station.

C. Crane-2-In accordance with 10 CFR 2.390 of the NRC's "Rules of Practice," a copy of this letter andits enclosure will be available electronically for public inspection in the NRC Public DocumentRoom or from the Publicly Available Records (PARS) component of NRC's document system (ADAMS), accessible from the NRC Web site at http://www.nrc.gov/reading-rm/adams.html(the Public Electronic Reading Room).

Sincerely,/RA/Mark A. Ring, ChiefBranch 1 Division of Reactor ProjectsDocket Nos. 50-461License Nos. NPF-62

Enclosure:

Inspection Report No. 05000461/2007007

w/Attachment:

Supplemental Informationcc w/encl:Site Vice President - Clinton Power StationPlant Manager - Clinton Power Station Regulatory Assurance Manager - Clinton Power Station Chief Operating Officer Senior Vice President - Nuclear Services Vice President - Operations Support Vice President - Licensing and Regulatory Affairs Manager Licensing - Clinton Power Station Senior Counsel, Nuclear, Mid-West Regional Operating Group Document Control Desk - Licensing Assistant Attorney General Illinois Emergency Management Agency State Liaison Officer, State of Illinois Chairman, Illinois Commerce Commission

SUMMARY OF FINDINGS

IR 05000461/2007007; 03/05/2007 - 03/23/2007; Clinton Power Station; Identification andResolution of Problems.The inspection was conducted by region-based inspectors, the resident inspectors atthe Clinton Power Station and the onsite IEMA inspector. One finding of very low safetysignificance (Green) was identified which involved an associated non-cited violation (NCV). The significance of most findings is indicated by their color (Green, White, Yellow, Red) usingInspection Manual Chapter (IMC) 0609, "Significance Determination Process," (SDP). Findingsfor which the SDP does not apply may be Green or be assigned a severity level after NRCmanagement review. The NRC's program for overseeing the safe operation of commercialnuclear power reactors is described in NUREG-1649, "Reactor Oversight Process," Revision 3,dated July 2000.Identification and Resolution of ProblemsIn general, the station identified issues and entered them into the corrective actionprogram (CAP) at the appropriate level. In addition, issues that were identified fromoperating experience reports and instances where previous corrective actions were ineffectiveor inappropriate were also entered into the CAP. The inspectors concluded that issues wereproperly prioritized and generally evaluated well. The inspectors determined that conditionsat the Clinton Power Station were conducive to identifying issues. The licensee staff at Clintonwas aware of and generally familiar with the CAP and other station processes, including theEmployee Concerns Program, through which concerns could be raised. One finding of verylow safety significance (Green) was identified during this inspection. A.Inspector-Identified and Self-Revealed Findings

Cornerstone: Barrier Integrity

Green.

The inspectors identified an NCV of 10 CFR Part 50, Appendix B, Criterion V,"Instructions, Procedures, And Drawings," for failure to assure that activities affectingquality be accomplished in accordance with prescribed documented instructions,procedures, or drawings. Contrary to procedure CPS 1019.05, "TransientEquipment/Materials," step 8.5.3, four radiation protection (RP) stanchions weresecured to the 755' elevation in the containment building with ty-raps instead of metalgrating clips. The licensee removed the stanchions, performed a walkdown ofcontainment to ensure there were no other improperly installed stanchions, and enteredthis performance deficiency into the CAP for resolution.This finding was associated with the Barrier Integrity Cornerstone. The finding wasmore than minor because the finding was viewed as a precursor to a significant event.If left uncorrected, the stanchions could become missiles during a suppression poolswell event, potentially damaging containment isolation valves. The inspectorsassessed the significance of this finding as very low safety significance (Green)

because the finding did not represent an actual open pathway in the physical integrity of the reactor containment. The finding was associated with cross-cutting aspect P.1(c),

Enclosure2Thoroughly Evaluate Problems, of the problem identification and resolution cross-cuttingarea, in that, the licensee's initial reviews of the issue failed to evaluate the potential design basis impact. (Section 4OA2.a)

B.Licensee-Identified Violations

No findings of significance were identified.

Enclosure3

REPORT DETAILS

4.OTHER ACTIVITIES4OA2Problem Identification and Resolutiona.Assessment of the Corrective Action Program(1)Inspection ScopeThe inspectors reviewed documentation for the past 3 years including: NRC inspectionreport findings, selected corrective action documents, licensee self-assessments,Nuclear Oversight (NOS) audits, operating experience reports and human performanceinitiatives to determine if problems were being identified and entered into the correctiveaction program (CAP) at the proper threshold. CAP implementation, metrics, andstatus, and departmental performance indicators were also reviewed and discussedwith the station staff.The inspectors also reviewed procedures, inspection reports, and corrective actiondocuments to verify that identified issues were appropriately characterized andprioritized in the CAP. Evaluations documented in condition reports (CRs) or issuereports (IRs) were evaluated for appropriateness of depth and thoroughness relative tothe significance or potential impact of each issue. Inspectors attended managementmeetings to observe the assignment of CR categories for current issues and to observethe review of root, apparent, and common cause analyses, and corrective actions forexisting CRs. In addition, the inspectors reviewed past inspection results, selected CRs and IRs,root cause reports, and common cause evaluations to verify that corrective actions,commensurate with the safety significance of the issues, were specified andimplemented in a timely manner. The inspectors evaluated the effectiveness ofcorrective actions. The inspectors also reviewed the licensee's corrective actionsfor NCVs documented in NRC inspection reports in the past 3 years. This inspection constitutes one biennial sample of problem identification and resolutionas defined by Inspection Procedure 71152.(2)AssessmentIdentification of IssuesThe inspectors concluded, in general, that the station identified issues and entered theminto the CAP at the appropriate level. The inspectors' review of operating experience reports identified that the licensee was appropriately including the issues into the CAP.

The licensee also used the CAP to document instances where previous corrective actions were ineffective or were inappropriately closed. The following paragraphs provide a specific review of the identification of issues on the reactor core isolation cooling (RCIC) system.

4An expanded 5 year review was conducted by the inspectors on the RCIC. Theinitial scope of the licensee's search of the CAP and work order databases for a 5-year period resulted in approximately 1300 documents being identified. From the inspectors' initial screening, approximately 100 issue reports/work orders were selected for further review and subdivided into specific categories.

Through the inspectors' review of the screened issue report/work order categories, and follow-up discussion with the licensee staff, approximately 20 issue reports were selected as an expanded sample. The issue statement that was developed for the review was focused on RCIC turbine/governor oil leaks impacting RCIC functionality.During the 5-year review period there were numerous issue reports relatedto RCIC turbine/governor oil leaks with a peak of approximately 10 issue reports in 2004 to a low of two issue reports in 2006. In all cases, RCIC operability was evaluated and determined to be unaffected based on minimal oil leak rate. For one occurrence, documented by IR 177868, compensatory actions were initiated by Operations to monitor turbine/governor oil leakage once a shift until the leaks were repaired. Additionally, evaluation EC 350620 performed for IR 240608 documented that minimal oil leaks/seepage did not affect the functionality/operability of the RCIC system. The identification of RCIC turbine/governor oil leaks since about 2004 within the CAP facilitated the required corrective actions, and a reduction in the number of oil leaks on the system. Through the additional review of the identification of issues, the inspectors developed anobservation regarding a specific occurrence of degrading pipe wall thickness of a service water supply line. This issue was not identified as a condition adverse to quality in the CAP. The following paragraphs provide this observation.Service Water Supply Line Degrading Pipe Wall ThicknessIn 2001, the licensee performed ultrasonic wall thickness examinations on the service water supply lines to the spent fuel pool. These areas were on the redundant A and B lines and the pipe sections were identified as 1SX12AA-2.5" and 1SX12AB-2.5".

The examinations noted wall loss on both lines and both areas were re-scheduled for examination in approximately 1 year. In September 2002, these areas were again examined. The wall thickness determined on the A line was 0.139 inches, and on the B line the wall thickness was 0.130 inches. Both of these lines were approaching the calculated code minimum wall thickness of 0.080 inches, and the evaluation recommended replacement of both lines within 6 months. The evaluation also stated that an inspection program ensures the wall thickness would not exceed the code minimum wall.In late 2003, from additional examinations, the wall thickness low reading on the A linewas 0.0100 inches, and on the B line the low reading was also 0.0100 inches. An evaluation was completed on the A line results, and EC 346745 concluded that this component would stay above the code minimum wall criteria for 5 more months, and was therefore acceptable until the scheduled replacement in February 2004. No corresponding evaluation was conducted on the B line results. The B line pipe section 5was not scheduled for replacement until February 2005. In early 2005, the B line wasexamined, with the lowest wall thickness determined to be 0.067 inches which was below the code minimum wall thickness of 0.080 inches. Additional code wall thickness analysis was contained in EC 346745 that showed the B line wall thickness determined by the 2005 examination was acceptable to allow replacement by February 2005. The B line 2003 examination results that determined degrading wall thickness were not identified as a condition adverse to quality in the CAP. However, the B line wall thickness was being monitored in a periodic examination program and was replacedbefore exceeding the EC 346745 wall thickness criteria of 0.037 inches.Prioritization and Evaluation of IssuesThe inspectors' observations of the Station Ownership Committee (SOC) concluded thatfor some IRs, additional follow-up activities were assigned that extended the time periodfor issue disposition within the organization. Using LS-CL-125-1001, "SOC ObservationForm," the review activities by SOC for some IRs appear to be similar to the warningflag pertaining to "spends time reviewing issue not for condition, but for cause." However, none of the issues that were assigned the additional follow-up resulted in aninappropriate prioritization based on significance. Examples of SOC action taken wereto assign work requests, evaluations, and/or corrective action to specific departmentalgroups. The inspectors observed the Management Review Company (MRC) function inan oversight role of the SOC. For example, the MRC changed the SOC recommendedaction of some issues based on committee dialogue and additional station awareness ofthe issue. The MRC performed grading of investigative CAP products to providefeedback on product quality to the sponsoring manager. The IRs that were observed being reviewed by the SOC were also observed beingreviewed by the MRC in their oversight role. The MRC member dialogue in the reviewof root, apparent, and common causes was informative, and provided feedback to thestaff on implementing the CAP. The inspectors concluded that issues were properlyprioritized and generally evaluated well.However, the inspectors developed observations regarding the prompt operability andreportablility basis of some IRs that were reviewed by SOC. The following paragraphsprovide these observations.Operability Basis Not DocumentedDuring the SOC review of March 9, 2007, IRs 601242, "UT on Piping Spool 1SX13AA-8Identifies Wall Loss," and 601262, "Cells 14 and 20 Resistance Above Acceptable Limit," did not have a prompt operability basis documented for either IR. The attending SOC members agreed to assign to the SOC engineering representative an action to obtain additional information for these IRs that would enhance their informative content.

This action was to be completed on day shift. The inspectors at the conclusion of the SOC review meeting questioned why these IRs were not reviewed for prompt operability by operations shift management within the same shift or by the oncoming shift in accordance with procedure LS-AA-120, "Issue Identification And Screening Process."

The SOC operations representative referred to procedure OP-AA-108-115, for operability determinations that allow for prompt operability decisions to be made 6within 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />. These IRs, as written, did not contain sufficient documentedinformation to be complete in describing the associated conditions. That is the basis why engineering accepted action to enhance the IRs' informative content.

Further discussion with the SOC operations representative and the operations director, resulted in the inspectors realizing that the prompt operability reviews were completed for each IR by operations shift management. However, operations shift management did not document in the IRs the current operability basis and the additional communications that were held with the engineering staff to conclude prompt operability.

IR 601586 was generated to identify the difference between procedures OP-AA-108-115 and LS-AA-120 for prompt operability decisions. In addition, IRs 601242 and 601262, were updated to document the current operability basis that had been previously determined.Reportable Basis Objective EvidenceDuring the SOC review of March 19, 2007, of IR 605619, "Effluent Wet Well OverflowsAt 14' 2" In Secondary Lagoon," the inspectors concluded that the IR's reportability basis lacked objective evidence. The reportability basis, in part, reads, "The last time the level in the effluent wet well was observed was at 2130 on 3/17/07. The water was identified to be slightly overflowing in the overflow pipe at 0955 on 3/18/07. There is no evidence that any overflow occurred prior to midnight 3/18/07. Hence, all discharge occurred during the current NPDES discharge week." The attending SOC members did not question this basis that was determined by operations shift and chemistry management. The inspectors discussed the conclusion that "there is no evidence that any overflow occurred prior to midnight 3/18/07," with the chemistry manager. The chemistry manager provided additional information, not documented in the original IR, on the communications held between his staff and operations. The chemistry manager also stated that a non-licensed operator (NLO) had observed at 0100 on 3/18/07 the wet well level was 1/4 to 1/16 inches from overflowing. The information provided by the chemistry manager resulted in the inspectors realizing that objective evidence did exist supporting the reportability basis. In addition, IR 605619 was updated to document the objective evidence.(3)Finding Procedure Non-ComplianceIntroduction: The inspectors identified a Green NCV of 10 CFR Part 50,Appendix B, Criterion V, "Instructions, Procedures, And Drawings," for failure to assure that activities affecting quality be accomplished in accordance with prescribed documented instructions, procedures, or drawings. Contrary toprocedure CPS 1019.05, "Transient Equipment/Materials," step 8.5.3, fourradiation protection (RP) stanchions were secured to the 755' elevation in thecontainment building with ty-raps instead of metal grating clips. Specifically,step 8.5.3 states, "to ensure that stanchions used in containment do not becomea missile hazard the requirements for securing stanchions in Appendix D shall befollowed." Appendix D identifies the design of the stanchions to be usedand references Drawing M26-1000-01AJ for the grating clips.

7Description: The four RP stanchions were used to post a contamination area around afire hose station on the 755' elevation. The RP stanchions were approximately 3 feet high with a support base of 12 by 12 inches, and weighed approximately 15 pounds.

The RP stanchions were approximately 6 feet apart making a square boundary around the fire hose station. The RP stanchions provided a holder for a nylon rope boundary around the contamination zone. The RP stanchions were located near the outer wall of the containment within the suppression pool swell zone. The swell zone is the area affected by the suppression pool during a reactor blow down (i.e., depressurization) to the suppression pool during a loss of coolant accident (LOCA). The RP stanchions were in-place since between May 26, 2006, and June 30, 2006, until they were removed on March 16, 2007.The improper securing of these RP stanchions was identified by the resident inspectorson March 15, 2007, during a tour of the containment building with licensee staff, and determined to be a performance deficiency. The licensee generated IR 604868 to document this issue on March 16, 2007. The Station Ownership Committee (SOC)closed IR 604868 on March 19, 2007, to actions already taken, contamination area de-posted and the RP stanchions removed, and to the planned action of re-emphasizing the requirements of procedure CPS 1019.05 to the radiation protection department. The Management Review Committee did not challenge the SOC documented actions for closure during its March 20, 2007, review of IR 604868. On March 21, 2007, the inspectors specifically identified to the licensee staff that IR 604868 did not include an evaluation of the station's compliance to its design basis during the time period the RP stanchions were in-place within the suppression pool swell zone. The licensee generated IR 607316 to document this issue on March 22, 2007.The licensee staff performed evaluation EC 365177, "Review of Design Basis of RPStanchions in Containment." The evaluation calculated the impact force on the bottom of a solid base RP stanchion from the suppression pool swell to be 1317 lbs. Since the ty-wraps were not able to withstand the force of the pool swell, a walk down was done to determine equipment that could have been hit by the RP stanchions, had the stanchions become missiles. The equipment identified by the licensee's walkdown that could affect containment isolation were valves 1FC007, the Fuel Pool Cooling and Cleanup (FC)

Containment Outlet Inboard Valve, and 1FP053, the Fire Protection (FP) Containment Inboard Isolation Valve. These motor operated valves are normally open and are inboard containment isolation valves. They automatically close on the Group 8 isolation signals of high drywell pressure or reactor level 2. Since during a pool swell event, the non-conforming RP stanchions could have damaged the flexible conduit or motor operators, these valves had the potential to fail open (i.e., as is), fail their design basis, and not close on a valid isolation signal. The licensee's evaluation conservativelyassumed that the missiles created could impinge on the two containment isolation valves and prevent their containment isolation function.Because the worst-case pool swell event is the result of a large line break LOCA in thedrywell, the high drywell pressure isolation would be expected to occur. An isolation signal would close both the inboard and outboard isolation valves in both the FC andFP lines. Therefore, the licensee's evaluation identified that the systems' functions werenot impacted by the possible failure of these valves, because the operable containment outboard isolation valves, 1FC008 and 1FP054, would have provided for containment 8isolation. In addition, the fire protection outboard containment isolation valve 1FP054 ismaintained normally closed, so the design basis of the containment penetration was maintained.Containment isolation is required following a LOCA-Loss of Offsite Power (LOOP)event. Since the two valves, 1FC007 and 1FP053, are inboard isolation valves, powered from Division 2, containment isolation can be assured if the Division 1 Diesel Generator (DG) was operable during the time the RP stanchions were in-place. If during the installation of the RP stanchions, a Division 1 DG were inoperable, such as, during a maintenance outage, then the outboard containment isolation valves would not have been able to automatically close. In this set of circumstances, the containment isolation function would not have been able to be completed. The licensee determined that the Division 1 DG was out of service on September 18, 2006, for 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br />, and October 2-5, 2006, for 79.2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br /> for a maintenance outage. In addition, the DG was taken out of service for 10 to 30 minutes each month for routine pre-start checks.

Therefore, when the Division 1 DG was out of service, the station did not meet General Design Criteria 54, which requires piping systems penetrating the containment to have redundant isolation.

Analysis:

The inspectors concluded that the performance deficiency was more thanminor because the finding is viewed as a precursor to a significant event because ifleft uncorrected, the stanchions could become missiles during a suppression pool swellevent, potentially damaging containment isolation valves. The inspectors reviewedAppendix B to Inspection Manual Chapter 0612 and determined that this finding was required to be evaluated by the Significance Determination Process due to its impact on the Barrier Integrity Cornerstone objective to provide reasonable assurance that physical design barriers (i.e., functionality of containment) protect the public from radio nuclide releases caused by accidents or events. The inspectors assessed the significance of this finding as very low safety significance (Green) because the finding did not represent an actual open pathway in the physical integrity of the reactor containment. Theinspectors determined that the finding was associated with a cross-cutting aspect in thearea of Problem Identification and Resolution, Corrective Action Program because thelicensee failed to thoroughly evaluate problems such that the resolutions addresscauses and extent of condition (P.1(c)). Specifically, the licensee failed to thoroughlyevaluate the impact on the design basis when the improper use of RP stanchions wasidentified through IR 604868.Enforcement: 10 CFR Part 50, Appendix B, Criterion V, "Instructions, Procedures,And Drawings," states, in part, activities affecting quality shall be prescribed by documented instructions, procedures, or drawings, of a type appropriate to the circumstances and shall be accomplished in accordance with these instructions, procedures, or drawings. Contrary to the above and procedure CPS 1019.05,"Transient Equipment/Materials," step 8.5.3, four radiation protection (RP)stanchions were secured to the 755' elevation in the containment buildingwith ty-raps instead of metal grating clips. Because this failure to comply with 10 CFR Part 50, Appendix B, Criterion V, is of very low safety significance and has been entered into the licensee's corrective action program as IRs 604868 and 607316, this violation is being treated as an NCV, consistent with Section VI.Aof the Enforcement Policy (NCV 05000461/2007007-01). Corrective actions for this 9NCV included licensee removal of the RP stanchions. Evaluation EC 365177documented the design basis review. A licensee walkdown was done which confirmed that there were no other incorrectly anchored stanchions in the containment.Effectiveness of Corrective Action In general, the licensee corrective actions for the samples reviewed were appropriate,and appeared to have been effective. The inspectors determined that the licensee generated IRs when a corrective action was identified which was either inadequate or inappropriate. However, the inspectors developed an observation regarding the development of corrective actions for a human performance deficiency that did not consider human factors associated with the nearly identical hardware. The following paragraphs provide this observation.Error Precursor Corrective ActionsThe Quick Human Performance Investigation (QHPI) performed for installing theincorrect carrier gas on the H2/O2 monitoring subsystem documented by IR 594756identified two "error precursors." One was related to hardware, the N2 & He carriergas bottles are essentially identical, and the other was related to human performance, complacency/lack of self checks or peer checks. The Exelon manual for preparing QHPIs, LS-AA-125-1003, "Apparent Cause Evaluation Manual," directs the development of "corrective actions that address the identified error precursors."The QHPI focused only on corrective action development for the human performancedeficiency, and did not consider human factors associated with the nearly identical hardware. The inspectors held a discussion with the QHPI investigator on the rationale for only addressing the human performance issue and not the hardware issue. The rational was that maintenance activities have been successfully performed at the facility where "nearly" identical items could potentially be mistakenly installed. The QHPI investigator and SOC concluded that this was an isolated human performance occurrence, and applying additional controls to the hardware issue were not warranted.

This information supporting the decision to not consider human factors was not documented in the QHPI. Issue Report 608300 was generated to identify this issue.b.Assessment of the Use of Operating Experience(1)Inspection ScopeThe inspectors reviewed the licensee's program for handling operating experience(OPEX). Specifically, the inspectors reviewed the implementing procedure, attendedcorrective action program meetings to observe the use of OPEX, reviewed OPEXevaluated by the station and reviewed selected 2007 OPEX Daily Event Reports.

10(2)AssessmentNo findings of significance were identified.In general, OPEX information was being well utilized at the station. The inspectorsobserved that Exelon fleet internal OPEX and industry OPEX were discussed by licensee staff to support review activities and CAP investigations. During licensee staff interviews, the inspectors identified that the use OPEX was being considered during daily activities.The inspectors verified that industry events were entered into the CAP and wereevaluated for impact at the facility. Specifically, two industry events were reviewed for licensee action, the recent jet pump nozzle cracks at Duane Arnold and flow accelerated corrosion on reactor vessel drain lines. Both of these industry events were entered into the licensee's CAP. Examinations were conducted on the Clinton reactor vessel drain line in response to the industry OPEX. The inspectors also verified that significant 2006 industry OPEX was addressed inthe licensee's CAP. The OPEX for this review included topics such as, safety related electrical power, internal flooding, pressure boundary degradation, environmental qualification, extended power uprate, circuit breakers, foreign material exclusion, human errors and safety related cooling. The inspector's review concluded that 80-plus IRs were related to the significant industry OPEX topical areas. However, the inspectors developed an observation regarding OPEX that was noteffectively applied in station procedures. The following paragraph provides this observation.EPRI-NMAC Report 1007460, "Terry Turbine Maintenance Guide"In September 2004, the licensee identified an enhancement opportunity to incorporateEPRI-NMAC Report 1007460, "Terry Turbine Maintenance Guide," into existingpreventive maintenance and surveillance procedures. The licensee's engineering,maintenance, and operations departments reviewed this report and determined that thechanges were not significant and incorporated the "Maintenance Guide" as a referenceonly in the maintenance procedures. In February 2006, the reactor core isolationcooling (RCIC) governor valve stem linkage setup was performed using the originalvendor manual guidance, and not the EPRI-NMAC Terry Turbine Maintenance Guide. In May 2006, the licensee started the RCIC turbine for surveillance testing and wasunable to control turbine flow at 620 gallons per minute (g.p.m.) as directed by thesurveillance procedure. Operators observed RCIC flow to rise to 681 g.p.m. when theturbine was started. This was higher than the surveillance acceptable range of 606 to620 g.p.m. Operations declared the RCIC turbine inoperable and conductedtroubleshooting between May 10 and May 12, 2006. The licensee conducted anequipment apparent cause evaluation. The apparent cause determined that conductingthe surveillance with the test return valves full open for in-service testing was incorrect. A contributing cause was the failure to incorporate the EPRI-NMAC Terry TurbineMaintenance Guide in the operations and maintenance procedures. This guide providedchanges to the linkage adjustment and surveillance testing that would have prevented 11the problem. The licensee re-performed the RCIC governor valve setup, changed thesurveillance procedure using the EPRI guidance, successfully completed thesurveillance, and declared the RCIC system operable. In this example, failure to use theEPRI-NMAC Terry Turbine Maintenance Guide resulted in the unplanned unavailabilityof the RCIC turbine. c.Assessment of Self-Assessments and Audits(1)Inspection ScopeThe inspectors reviewed selected focused area self-assessments (FASA), check-inself-assessments, and Nuclear Oversight (NOS) audits of the corrective action program,technical human performance, engineering design control and programs, maintenance,operations and system performance monitoring. The inspectors evaluated whetherthese audits and self-assessments were being effectively managed, were adequatelycovering the subject areas, and were properly capturing identified issues in the CAP. Inaddition, the inspectors also interviewed licensee staff regarding the implementation ofthe audit and self-assessment programs.(2)AssessmentNo findings of significance were identified.The inspectors concluded that the self-assessments and NOS audits were generallycritical and probing. Multi-discipline teams were utilized, when appropriate, to gain abroad perspective. The use of OPEX supported team preparations and scopedevelopment of the NOS audits. There were a number of deficiencies,recommendations and strengths identified across the spectrum of performance,including issues of improper CAP implementation. As appropriate, the self-assessmentand NOS audit deficiencies were documented in the CAP. The licensee performed Check-In Self-Assessment 284483, "System PerformanceMonitoring," in May 2005. The self-assessment reviewed system performancemonitoring with a focus on the effectiveness of system performance teams inmeeting engineering management and policy expectations. The system performancemonitoring teams selected were reviewed for various attributes, such as, cross-functional participation in quarterly meetings and walkdowns, senior managementsponsor participation, publication of team results and integration of system performanceimprovement plans into system notebooks. Three self-assessment deficiencies wereidentified and entered into the CAP under separate IRs. The self-assessment identifieddeficiencies with system performance monitoring teams not holding meetings quarterly,the lack of senior management sponsor participation and inconsistent team memberparticipation on the quarterly walkdowns.The licensee performed NOS Audit NOSA-CPS-06-01, "Maintenance Functional Area,"in March 2006. One of the common audit deficiencies that was identified had fleet-wideapplicability based on utilization of a standardized process. This deficiency involved thelack of corrective action being implemented for Exelon's OPEX Nuclear Event Report(NER) BW-04-099, "Unclear Expectations for Work in the Area of Protected Equipment."

12Fleet-Wide actions designated for the NER response, IR 274947, included evaluation ofthe contractor in-process training and inclusion of the NER in contractor lessons learnedtailgates. The licensee's evaluation resulted in the initiation of training request 04-1407. The nuclear employee in-processing training lesson plan was to be revised to include adefinition of the protected equipment process and personnel expectations whenencountering protected equipment signs. However, the training request was closedwithout the lesson plan being revised. The licensee generated IR 449636 during theaudit for this issue. d.Assessment of Safety-Conscious Work Environment(1)Inspection ScopeThe inspectors interviewed selected members of the Clinton station staff to determine ifthere were any impediments to the establishment of a safety conscious workenvironment. In addition, the inspectors discussed the implementation of the EmployeeConcerns Program (ECP) with the ECP Coordinators, and reviewed their 2006/2007activities to identify any emergent issues or potential trends. Licensee programs topublicize the CAP and ECP programs were also reviewed. In addition, FASA 476076conducted on the corrective action program in January 2007, was reviewed for ECPissues.(2)AssessmentNo findings of significance were identified.The inspectors determined that the conditions at the Clinton station were conducive toidentifying issues. The staff was aware of and generally familiar with the CAP and otherstation processes, including the ECP, through which concerns could be raised. Staffinterviews identified that issues could be freely communicated to supervision, and thatseveral of the individuals interviewed had previously initiated IRs. In addition, a reviewof the types of issues in the ECP indicated that site personnel were appropriately usingthe corrective action and employee concerns programs to identify issues. Theinspectors interviewed the ECP Coordinators and concluded that the individuals werefocused on ensuring all site individuals were aware of the program, comprehensive intheir review of individual concerns, and used the corrective action and employeeconcerns programs to appropriately resolve issues.The corrective action program FASA 476076 identified an ECP deficiency. The specificdeficiency was that new employees were not meeting with an ECP coordinator in accordance with HR-AA-4000, "Employees Entering or Transferring Within Nuclear Stations," Revision 2. The licensee generated IR 587003 to document this deficiency.

In response to IR 587003, human resources generated a list of new hires within the last 90 days. The inspectors interviewed approximately 50 percent of the new hires. These interviews revealed that the new hires had already been presented an ECP orientation by the ECP coordinators. Also, the new hires were aware of the corrective action andemployee concerns programs through which issues could be identified to supervision.

134OA6Management MeetingsExit Meeting SummaryThe inspectors presented the inspection results to Mr. Kearney and other members ofthe Clinton staff at an exit meeting on March 23, 2007. Mr. Kearney acknowledged the finding presented, and indicated that no proprietary information was provided to the inspectors.ATTACHMENT: