IR 05000298/2005015

IR 05000298-05-015; 11/7/05 - 03/14/06; Cooper Nuclear Station. Other Activities

ML061160027
Person / Time
Site:	Cooper
Issue date:	04/25/2006
From:	Kennedy K M NRC/RGN-IV/DRP/RPB-C
To:	Edington R K Nebraska Public Power District (NPPD)
References
IR-05-015
Download: ML061160027 (29)

Text

April 25, 2006

Randall K. Edington, Vice President-Nuclear and CNO Nebraska Public Power District

P.O. Box 98 Brownville, NE 68321

SUBJECT: COOPER NUCLEAR STATION - NRC SPECIAL INSPECTIONREPORT 05000298/2005015

Dear Mr. Edington:

On March 14, 2006, the U.S. Nuclear Regulatory Commission (NRC) completed an inspectionat your Cooper Nuclear Station. The enclosed inspection report documents the inspection findings which were discussed on November 23, 2005, with Mr. S. Minahan, General Manager of Plant Operations, and other members of your staff. Additional in-office reviews were conducted and the final inspection results were discussed with Mr. Minahan and your staff on March 14, 2006.This inspection examined activities conducted under your license as they relate to safety andcompliance with the Commission's rules and regulations and with the conditions of your license.

Specifically, the inspector reviewed the circumstances surrounding a service water systemfailure on October 20, 2005.This report documents two NRC-identified findings that were evaluated under the risksignificance determination process as having very low safety significance (Green). The NRC has also determined that a violation is associated with one of these issues. This violation isbeing treated as a noncited violation (NCV), consistent with Section VI.A of the Enforcement Policy. The NCV is described in the subject inspection report. If you contest the violation or significance of the NCV, you should provide a response within 30 days of the date of this inspection report, with the basis for your denial, to the U.S. Nuclear Regulatory Commission, ATTN: Document Control Desk, Washington, D.C. 20555-0001, with copies to the Regional Administrator, U.S. Nuclear Regulatory Commission, Region IV, 611 Ryan Plaza Drive, Suite 400, Arlington, Texas 76011-4005; the Director, Office of Enforcement, U.S. Nuclear Regulatory Commission, Washington, D.C. 20555-0001; and the NRC Resident Inspector atthe Cooper Nuclear Station facility.In accordance with 10 CFR 2.390 of the NRC's "Rules of Practice," a copy of this letter, and itsenclosure, will be available electronically for public inspection in the NRC Public DocumentRoom or from the Publicly Available Records component of NRC's document system (ADAMS).ADAMS is accessible from the NRC Web site at http://www.nrc.gov/readingrm/adams.html (thePublic Electronic Reading Room).

Nebraska Public Power District- 2 -Should you have any questions concerning this inspection, we will be pleased to discuss themwith you.

Sincerely,/RA/Kriss M. Kennedy, ChiefProject Branch C Division of Reactor ProjectsDocket: 50-298License: DPR-46

Enclosure:

NRC Inspection Report 05000298/2005015

w/attachments:

Supplemental Information Special Inspection Chartercc w/enclosure:Gene Mace Nuclear Asset Manager Nebraska Public Power District

P.O. Box 98 Brownville, NE 68321John C. McClure, Vice President and General Counsel Nebraska Public Power District

P.O. Box 499 Columbus, NE 68602-0499P. V. Fleming, Licensing ManagerNebraska Public Power District

P.O. Box 98 Brownville, NE 68321Michael J. Linder, DirectorNebraska Department of Environmental Quality P.O. Box 98922 Lincoln, NE 68509-8922 Nebraska Public Power District- 3 -ChairmanNemaha County Board of Commissioners Nemaha County Courthouse 1824 N Street Auburn, NE 68305Julia Schmitt, ManagerRadiation Control Program Nebraska Health & Human Services Dept. of Regulation & Licensing Division of Public Health Assurance 301 Centennial Mall, South P.O. Box 95007 Lincoln, NE 68509-5007H. Floyd GilzowDeputy Director for Policy Missouri Department of Natural Resources

P. O. Box 176 Jefferson City, MO 65102-0176Director, Missouri State Emergency Management Agency

P.O. Box 116 Jefferson City, MO 65102-0116Chief, Radiation and Asbestos Control Section Kansas Department of Health and Environment Bureau of Air and Radiation 1000 SW Jackson, Suite 310Topeka, KS 66612-1366Daniel K. McGheeBureau of Radiological Health Iowa Department of Public Health Lucas State Office Building, 5th Floor 321 East 12th Street Des Moines, IA 50319Ronald D. Asche, President and Chief Executive Officer Nebraska Public Power District 1414 15th Street Columbus, NE 68601 Nebraska Public Power District- 4 -Jerry C. Roberts, Director of Nuclear Safety Assurance Nebraska Public Power District

P.O. Box 98 Brownville, NE 68321John F. McCann, Director, LicensingEntergy Nuclear Northeast Entergy Nuclear Operations, Inc.

440 Hamilton Avenue White Plains, NY 10601-1813Keith G. Henke, PlannerDivision of Community and Public Health Office of Emergency Coordination 930 Wildwood, P.O. Box 570 Jefferson City, MO 65102 Nebraska Public Power District- 5 -Electronic distribution by RIV:Regional Administrator (BSM1)DRP Director (ATH)DRS Director (DDC)DRS Deputy Director (RJC1)Special Inspection Team Leader (JDH1)Senior Resident Inspector (SCS)Branch Chief, DRP/C (KMK)Senior Project Engineer, DRP/C (WCW)Team Leader, DRP/TSS (RLN1)RITS Coordinator (KEG)DRS STA (DAP)S. O'Connor, OEDO RIV Coordinator (SCO)ROPreports CNS Interim Site Secretary Assistance (DVY)SUNSI Review Completed: _kmk__ADAMS: X Yes G No Initials: _kmk_____ X Publicly Available G Non-Publicly Available G SensitiveX Non-SensitiveR:\_REACTORS\_CNS\2005\CN2005-15RP-JDH.wpdRIV:RI:DRP/CSRI:DRP/ESRA:DRSC:DRP/CNHTaylorJDHannaRLBywaterKMKennedy E - KMKennedy E - KMKennedy E - KMKennedy

/RA/4/24/064/24/064/24/064/25/06OFFICIAL RECORD COPY T=Telephone E=E-mail F=Fax Enclosure-1-U.S. NUCLEAR REGULATORY COMMISSION REGION IV Docket:50-298 License:DPR-46 Report:05000298/2005015 Licensee:Nebraska Public Power District Facility:Cooper Nuclear StationLocation:P.O. Box 98 Brownville, Nebraska Dates:November 7, 2005, to March 14, 2006 Inspector:J. Hanna, Senior Resident Inspector, Fort Calhoun StationN. Taylor, Resident InspectorApproved By:K. Kennedy, Chief, Project Branch C, Division of Reactor Projects Enclosure-2-

SUMMARY OF FINDINGS

IR 05000298/2005015; 11/7/05 - 03/14/06; Cooper Nuclear Station. Other Activities.The report documents special inspection activities conducted by a senior resident inspector anda resident inspector. One Green noncited violation and one Green finding were identified. The significance of the issues is indicated by their color (Green, White, Yellow, or Red) and was determined by the significance determination process in NRC Inspection Manual Chapter 0609. Findings for which the significance determination process does not apply are indicated by the severity level of the applicable violation. The NRC's program for overseeing the safe operationof commercial nuclear power reactors is described in NUREG-1649, "Reactor OversightProcess," Revision 3, dated July 2000.A.

Cornerstone: Mitigating Systems

Green.

The inspectors identified a noncited violation of 10 CFR Part 50,Appendix B, Criterion XVI, for failure of the licensee to take adequate and timely corrective action to prevent recurrence of a significant condition adverse to quality.

Specifically, the licensee's corrective actions taken since a service water strainer clogging event in November 2004 did not preclude the event from occurring in October 2005. The effect of these events was to cause a loss of both trains of service water for a short period of time and potentially challenge the cooling function to downstream components.This finding affected the Initiating Events and Mitigating Systems Cornerstonessince the loss of service water is an initiating event and the service water system isrequired to mitigate the consequences of an accident. The finding was more than minor since it could reasonably be viewed as a precursor to a significant event and it affected the cornerstone attribute of availability and reliability of mitigatingequipment. Since two cornerstones were affected by the finding, a Significance Determination Process Phase 2 analysis was required. The finding was determined to be

Green.

Crosscutti ng aspects associated with problemidentification and resolution were identified based on the fact that it was within the licensee's capability to have determined and corrected the problem prior to thefailures in October 2005, yet they failed to do so. (Section 4OA5.3).*Green. The inspectors identified a Green finding for failure of the licensee toimplement a commitment made to the NRC. Specifically, the licensee did notcarry out the programmatic service water intake bay inspections described in their response to NRC Generic Letter 89-13, "Service Water System Problems AffectingSafety-Related Equipment."The finding was more than minor since not performing the inspections couldbecome a more significant safety concern if left uncorrected, as degraded conditions in the service water intake bay could affect the operability of theultimate heat sink for the facility. This finding is not suitable for significance Enclosure-3-determination process evaluation, but was reviewed by NRC management anddetermined to be of very low safety significance due to the fact that it did not result in an increase in the likelihood of an initiating event and did not result in the actual degradation of a mitigating system. The inspectors identified cro sscutti ng aspectsin problem identification and resolution in that this disparity was identified by the NRC in 1994 and again by the licensee in 2003 without any corrective actionsbeing taken (Section 4OA5.9).

B. Licensee Identified Violations

None.

Enclosure-4-

REPORT DETAILS

4.OTHER ACTIVITIES4OA5Other Activities1.Description and Sequence of EventsOn October 19, 2005, operator logs indicated a trend of degrading service water (SW)system performance. The symptoms included high sedimentation in the SW intake bay(Bay E) in excess of 3 feet, SW pump (SWP) gland water low flow alarms, and SW strainer high differential pressure (DP) alarms. In one shift, operators logged six occurrences where the SW strainer high DP alarm was received in the control room.

Despite these mounting indications of a sedimentation problem, no actions were taken to protect the SW system.On October 20, 2005, during an extent of condition review for the failure of a motor-operated valve to close, operations personnel prepared to cycle residual heatremoval (RHR) Heat Exchanger (HX) B SW Outlet SW-MOV-89B. In order to establishthe plant conditions required to open this valve, operators planned to start a fourth SW pump (Pump D) to meet the additional flow demand as the RHR HX was placed inservice. As required by the licensee's procedure, the SW intake bay spargers were cycled immediately prior to starting SWP D. (All four SW pumps take a suction on theSW intake bay, and the function of the spargers is to prevent debris buildup at the suction of the pumps.) Shortly after SWP D was started, SWP Strainers A and B became clogged and system low pressure alarms were received in the control room. The time line below describes the major events and the operator/system res ponses thatoccurred on October 20. 9:08a.m.Operators started SWP D.

9:09a.m.SW Discharge Strainer B high DP alarm received (5 psid).

9:11a.m.SW Discharge Strainer A high DP alarm received (5 psid).

9:12a.m.Control room operators noted that Division 1 SW booster pump suctionpressure was at 39 psig and lowering.9:12a.m.SW Header A low pressure alarm received (17 psig). Valve SW-MOV-36(noncritical SW header isolation valve) closed on low system pressure(38 psig).9:12a.m.SW Header A low pressure and SW Discharge Strainer A high DP alarmsclear.9:12a.m.SWP B header low pressure alarm received. Valve SW-MOV-37(noncritical SW header isolation valve) closed on low system pressure. Turbine equipment cooling was isolated.

-5-9:13a.m.Operators noted Division 1 SW pressure at 70 psig and reopenedValve SW-MOV-36. Operators attempted to reopen Valve SW-MOV-37, which immediately reclosed due to low pressure in Division 2 SW.

Turbine equipment cooling was restored from Division 1 SW.9:15a.m.Operators began to bypass SW Strainer B.

9:24a.m.SW Header B low pressure alarmed and SW Strainer B high DP alarmcleared.The combination of elevated sediment levels in the SW intake bay, rotation of the SWintake bay spargers, and the starting of SWP D led to a simultaneous plugging of both SW strainers and a total loss of SW for a few seconds. During this short period of time, the automatic closing function of Valves SW-MOV-36 and SW-MOV-37 functioned properly and isolated all cooling to the noncritical SW loop (including the turbine equipment cooli ng system). The SW Strainer A successfully backwashed andDivision 1 was restored approximately 5 minutes after the event began, precluding what would have been a manual scram of the reactor on prolonged loss of turbine equipment cooling water. The filtering function of SW Strainer B was overwhelmed by the inrush of sediment, and the automatic backwash function failed due to lack of any downstream pressure (the motive force for backwashing).

Based on system walkdowns, review of operating procedures, design basis documents,recorded data, and interviews with the station operators who were on watch during the transient, the inspectors concluded that all safety systems performed as designed withthe exception of SW Strainer B. The SW Strainer B backwash feature was ineffective and required operators to bypass the strainer to restore pressure to Division 2 SW.The inspectors reviewed standard operating procedures, emergency procedures, designdocuments, and recorded data and conducted interviews to evaluate the operators'response to the event. No discrepancies were noted in operator actions after the event began. The inspectors did note that various operators on watch when the event occurred had a different understanding of the entry conditions for System Operating Procedure 2.2.3.1, "Traveling Screen, Screen Wash, and Sparger System," which provided action levels for sanding conditions in the SW intake bay. The inspectors determined that this lack of a common understanding of the procedural requirements contributed to the operators' failure to respond to precursor alarms received immediately prior to the event.The NRC evaluated these SW system failures in accordance with ManagementDirective 8.3, "NRC Incident Investigation Program," and determined the need toconduct a special inspection to evaluate the cause of the failures and to assess the licensee's corrective actions. The inspection charter is included as Attachment 2 to this report.2.Similar SW System ChallengesThe inspectors reviewed similar chall enges to the SW system since January 2003resulting from the introduction of debris into the SW system. The inspectors reviewed

-6-these previous transients in order to better understand the frequency of thedebris/sedimentation effects and the potential adverse effects. In particular the inspectors evaluated the more significant transients (e.g,. those where strainer DP exceeded 15 psid which results in inoperability of the component). The inspectors didnot include events where the system responded properly and the condition was self-corrected (e.g., strainer DP reaches the setpoint and backwash is successful).ConditionReportDateDescription of Event2003-00461-6-03Debris caused the thermal overloads on the SW Strainer Bmotor to trip. Strainer DP did not exceed 15 psid and the system safety function was maintained. The strainer was not manually bypassed.2003-02711-21-03SW Strainer B high DP (14.5 psid). Operators declaredDivision 2 SW inoperable due to erratic DP indications before and after strainer backwash.2003-49368-27-03High DP on SW Strainer A (< 15 psid). The subsequentdrop in Division 1 SW pressure resulted in entry into SW Emergency Procedure 5.2. Pressure recovered and the system remained operable.2004-40465-29-04Shear pin broke on SW Strainer B. Strainer DP reached15.2 psid. Operators declared SW Division 2 inoperable.2004-740911-20-04High DP on SW Strainer A (> 15 psid) after starting SWP D,followed by high DP on SW Strainer B (pegged high), which did not clear. Loss of SW pressure resulted in automatic system isolations. Operators declared both trains of SW inoperable and entered SW Emergency Procedure 5.2. 2004-56828-5-05Following the start of J4-B2 spargers in the SW intake bay,a shear pin broke on the SW Strainer A causing a high DP condition for 38 seconds. Strainer DP exceeded 15 psid. 2004-774710-20-05High DP on SW Strainer A (> 15 psid) after starting SWP D,followed by high DP on SW Strainer B (pegged high), which did not clear. Loss of SW pressure resulted in automatic system isolations. Operators declared both trains of SW declared inoperable and entered SW Emergency Procedure 5.2.3.Corrective Actions for Previous Events

a. Inspection Scope

The inspectors reviewed the adequacy and timeliness of the licensee's correctiveactions established prior to the event on October 20, 2005, to prevent recurrence of SW

-7-strainer clogging and challenges to the operability of the service water system. Theinspectors also examined the licensee's corrective actions following the event in an attempt to determine if those actions would be effective at preventing recurrence.

b. Findings

Introduction.

The inspectors identified a Green noncited violation of 10 CFR Part 50,Appendix B, Criterion XVI, for the licensee's failure to take adequate and timely corrective action to prevent recurrence of a significant condition adverse to quality.

Specifically, the licensee's corrective actions taken following a SW strainer clogging event in November 2004, did not preclude the event from occurring in October 2005. The effect of these events was to cause a loss of both trains of SW for a short period of time and potentially challenge the cooling function to downstream components.Description. In response to the November 20, 2004, SW strainer clogging event, thelicensee initiated Condition Report CR-CNS-2004-07409. The root cause analysis for this condition report identified that:

(1) changing river conditions were causing higher levels of sediment being transported into the SW intake bay; and

(2) monitoring, operation, design and maintenance of SW intake structure related equipment were not effective in mitigating sediment intrusion. The inspectors reviewed the corrective actions associated with these two causes.Effectiveness of Prior Corrective ActionsFollowing the November 2004 SW strainer clogging event, the licensee identifiedcorrective actions designed to prevent recurrence of the event. These actions included (but were not limited to):*Implementing a calender-based SW strainer cleaning interval - The licensee hadhistorically used a condition-based approach to cleaning the strainer (e.g., a high DP alarm would cause the licensee to clean the strainer). The licensee added a calendar based frequency (routine cleaning every 6 weeks) in conjunction with the condition based frequency. The intent of this change was to maintain the strainers as clean as possible to improve their performance in the event of a large influx of debris.*Altering the SW pump operation cycle - The licensee increased the fr equency atwhich the idle SW pump was started and a running pump was secured to daily.

This action was intended to minimize the possibility of sediment buildup adjacentto an idle SW pump and decrease the probability of a significant influx of debrisfollowing the start of a pump that had been idle for a longer period of time.*Determining SW intake bay sediment levels requiring increased monitoring andaction - The licensee established alert/action levels for monitoring sediment levels in the SW intake bay and corresponding required actions. These actions included:

(1) determining sediment levels in SW intake bay and increased monitoring if river level changed greater than 1 foot/day,

(2) increased monitoring to every other day if SW intake bay levels were greater than 2.25 feet, and

(3) removing sediment from the SW intake bay if levels were greater than 2.5 feet. The purpose of these

-8-actions was to limit the amount of sediment in the SW intake bay and alertoperators when conditions favorable to a SW strainer clogging event were present.*Developing organizational lessons learned from the event, including effectivecommunication, sense of urgency responding to issues, and operational focus.The inspectors found that although the licensee had completed these corrective actions,they were inadequate in preventing the October 2005 event. For example, while detailed thresholds and specified actions were delineated based on SW intake bay debris levels, these limits and the procedurally required actions were unsuccessful at preventing a significant sediment event from occurring. Further, the inspectors found through interviews with the operating crew on watch at the time of the October 2005 event that there was a lack of common understanding of what indications to use and what actions were required to be taken. The inspectors determined that the expectations had not been communicated effectively to the operators.The inspectors also observed that the licensee's root cause analysis for the October 20,2005, event concluded that a human performance aspect of not responding to precursors was a factor. The inspectors noted this was similar to the "sense of urgency" or "operational focus," which were factors in the November 2004 event as described in CR-CNS-2004-7409. Prior to the October 2005 event, control room operators had indications that sediment levels in the SW intake bay were elevated (in excess of 2.0 feet), but did not take any action based on these indications. Additionally, the inspectors noted that there were approximately 12 instances in which strainer DP spiked high in the 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> prior to the October 2005 event.Timeliness of Corrective ActionsIn addition to the corrective actions listed above, the licensee identified other correctiveactions following the November 2004 event. However, at the time of the October 2005 event, 11 months after the November 2004 event, the licensee had not completed these actions. The inspectors concluded that these actions were not completed in a timely manner. These actions included:*Modifying the setpotint for automatic strainer backwash - The corrective actiondocument specified changing the setpoint at which automatic strainer backwashoccurred from 4.0 psid to 3.0 psid. The licensee believed that lowering the setpoint would reduce the amount of debris that might accumulate on the strainersimmediately prior to an event and increase the likelihood that a strainer would automatically recover in the event of a large influx of sediment.*Altering the frequency at which the strainers were periodically backwashed - Thecorrective action report required changing the frequency at which strainer backwash occurred from every 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> to every 2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br /> to reduce the amount of debris that might accumulate on the strainers immediately prior to a large intrusion of sediment and increase the likelihood that a strainer would automatically recoverduring a large intrusion of sediment.

-9-*Modifying the strainer DP alarm setpoint - The corrective action documentrecommended that if the strainer backwash setting was changed from 4.0 to 3.0 psid, that the alarm setpoint should be changed from 6.0 psid to 5.0 psid. Thepurpose of this change was to provide operators with earlier indication of the onset of a SW debris event.*Implementing weir wall modifications and installing river turning vanes - Thelicensee completed installing turning vanes in the river bed on September 1, 2005.

However, the licensee also planned to alter the weir wall profile. The inspectors noted that, in order for the turning vanes to be effective at minimizing sedimentation transported into the intake structure, they had to work in conjunction with the weir wall modification. The licensee planned to complete this modification during Refueling Outage 1R23 in October 2006.Analysis. The inspectors concluded that the licensee failed to take effective and timelycorrective actions to prevent recurrence of debris clogging of both trains of SW strainers. Successfully completing these actions was reasonably within the licensee's ability to do so, based on the history of SW debris events, the time since the lastsignificant debris event, the precursors to the debris events, and the availability ofapplicable industry operating experience. Therefore, the inadequate and untimelycorrective actions, which resulted in the clogging of the SW strainers, was determined to be a performance deficiency. This finding affected the Initiating Events and Mitigating Systems Cornerstones since the loss of SW is an initiating event and the SW system isrequired to mitigate the consequences of an accident. The finding was more than minor since it could reasonably be viewed as a precursor to a significant event and it affected the cornerstone attribute of availability and reliability of mitigating equipment. A modified Phase 2 significance determination process (SDP) analysis was performedby a senior reactor analyst. Key assumptions used in this analysis included:*The exposure time used in Table 1 of the Risk-Informed Inspection Notebook forCooper Nuclear Station (SDP Phase 2 Notebook, Revision 2) was 3-30 days. This was based on the number of days prior to the November 2004 event that degraded conditions existed in the SW intake bay (5 days) and the number of days prior to the October 2005 event that degraded conditions existed in the SW intake bay(1 day).*The applicable initiating event scenario evaluated for this finding was loss ofSW (LOSW).*The initiating event likelihood was increased to 1 based on the occurrence of theNovember 2004 and October 2005 events.*Full mitigation capability credit was assumed for the reactor core isolation and highpressure core injection since these systems can operate for some period of timewithout SW. *Recovery of SW flow in a loop with a clogged strainer can be accomplished byopening the associated strainer bypass valve.

-10-*A clogged strainer can be cleaned and returned to service in less than 8 hours9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br />.*A Recovery Credit of 4 was used based on the probability that the bypass valvefails to open (6E-6) and the probability that operators fail to open the valve (HumanError Probability = 1.16E-4). Using the above assumptions, the results of evaluating the most dominant core damagesequences for the LOSW initiator worksheet are shown below.SEQUENCEIELREMAININGMITIGATIONCAPABILITY RATINGRECOVERYCREDITRESULTSLOSW - RECSW24 - LI 11 + 248LOSW - RECSW24 - CV 11 + 248 LOSW - RCIC - LI 11 + 248 LOSW - RCIC - CV 11 + 248The analyst determined that external initiating events did not contribute significantly tothe overall significance of the finding. The analyst also determined that any change inlarge early release frequency did not contribute to the significance of the finding.Using the above assumptions in the Modified SDP Phase 2 Analysis, the finding wasdetermined to be of very low safety significance (Green).This finding had crosscutting aspects associated with problem identification andresolution. The failure to implement effective and timely corrective actions contributed to the SW strainer clogging event in October 2005.

Enforcement.

Title 10 CFR Part 50, Appendix B, Criterion XVI, requires that measuresshall be established to assure that conditions adverse to quality are promptly identified and corrected. In the case of significant conditions adverse to quality, the measures shall assure that the cause of the condition is determined and corrective action taken to preclude repetition. Contrary to this requirement, Cooper Nuclear Station failed to correct and preclude repetition of a significant condition adverse to quality. Specifically, on October 20, 2005, both trains of SW strainers became clogged due to ingestion of sediment/debris. Cooper Nuclear Station experienced a similar clogging event approximately 11 months earlier, but failed to take timely and effective corrective actions to prevent further failures. Because this finding is of very low safety significance and has been entered in thelicensee's corrective action program as Condition Report CR-CNS-2005-7772, this violation is being treated as a noncited violation consistent with Section VI.A of the NRCEnforcement Policy (NCV 05000298/2005015-01, Inadequate Corrective Actions for Service Water Strainer Clogging Event). Unresolved Item (URI)05000298/2005002-09, Both SW Discharge Strainers CloggedDue to Silt Intrusion, is being closed to this violation.

-11-4.Corrective Actions Implemented Following the October 2005 EventFollowing the October 2005 event, the licensee instituted a number of interim correctiveactions including:*Cleaned and inspected SW Strainers A and B.

• Limited the number of running circulating water pumps to three during continuousoperation. The licensee believed that this would minimize the amount of turbulence outside the SW intake bay and minimize the amount of sand/debris being transported into the intake structure.*Established a limit of 2.5 feet of sediment in the SW intake bay downstream of thetraveling water screen. The licensee believed that this would minimize the amount of debris accumulation available for transport into the SW system.*Established a rotation frequency for SW intake bay spargers of approximatelyevery 3 hours3.472222e-5 days <br />8.333333e-4 hours <br />4.960317e-6 weeks <br />1.1415e-6 months <br />. If the SW intake bay spargers cannot be rotated every 3 hours3.472222e-5 days <br />8.333333e-4 hours <br />4.960317e-6 weeks <br />1.1415e-6 months <br /> or are out of service, the intake Bay D to SW intake bay crosstie valve may be used to supply water to the SW pumps through the circulating water intake Bay D. The licensee believed that the more frequent rotation of the spargers would minimize the amount of sand accumulation.*Changed the operation of the SW strainers such that the strainers would bemaintained in continuous operation for 10 minutes after and until strainer DPs are stable following any SW intake bay evolution, including SW intake bay sparger or SW pump swaps, starts or stops. The licensee believed that this would ensure that the SW strainers would have time to backwash additional debris entrained in the SW flow.The inspectors found that these actions appeared to be technically acceptable andappropriate. Though the inspectors were unable to predict with certainty the effectiveness of the current compensatory measures, the inspectors verified that theyare being performed and/or have been incorporated into the licensee's procedures. 5.Additional Actions PlannedThe inspectors also noted that the following corrective actions related to the SW strainerclogging events:*Conduct visual inspections for macroscopic biofouling and corrosion of the intakestructure once per refueling cycle. The inspectors noted that the licensee did not plan to assess the conditions below the surface of the water. Refer to Section 4OA5.9 of this report.*Perform an annual depth survey in the area between the trash rack and the weirwall.

-12-*Dredge the front of the intake structure to ensure sand build-up in front of theintake is not excessive. Recent low river levels have resulted in a frequency of once/cycle for this activity.*Modify and replace the circulating water and SW intake bays' traveling screenswith a new design. The inspectors noted that, though the mesh size of the new screens was smaller than the previous design, the openings were still larger thanthose on the SW strainers. Consequently, debris plugging events were still possible.*Form a cross-discipline team to evaluate the design challenges to the SW systemto preclude future events. 6.SW Licensing and Design Basis Requirements

a. Inspection Scope

The inspectors reviewed the evaluation performed by the licensee to verify the ability ofthe SW system to continue to meet design requirements. The inspectors compared theresults of the licensee's evaluation with the Cooper Nuclear Station licensing and design basis.

b. Findings

Introduction.

The inspectors identified an unresolved item regarding the potentialdeposition of sediment to the reactor equipment cooling (REC) HXs by the SW systemduring design basis accidents. This finding is unresolved pending the NRC's review oflicensee calculations.Description. During a design basis accident (e.g., a loss-of-coolant accident) the SWsystem provides cooling to safety-related equipment, including the REC system HXs. The REC system is a closed system which provides cooling to various equipment roomsand the residual heat removal pumps seals.The inspectors reviewed a licensee analysis, "Determination of the SedimentationCharacteristics in the Service Water System," dated October 31, 2000. The inspectors noted that the median particle size of 0.4 mm assumed in this analysis was based on data gathered at the traveling screens in front of the SW intake structure in 1999. Theinspectors considered the material withdrawn from the SW strainers following the recent plugging events to be more representative of the sediment that would be present in thesystem. The material removed from the strainers following the November 2004 andOctober 2005 events was characterized as "torpedo gravel . . . wedge[d] into the openings (1/8") of the strainer basket." This meant that the upper bound of the sediment size was approximately 3.0 mm. In the event that operators bypassed the SWstrainers, this sediment would be transported through the SW system to thecomponents cooled by the system.To assess the potential adverse effects of bypassing the SW strainers on safety-relatedequipment, the inspectors reviewed data for normal and postaccident SW flow rates to

-13-various systems. For the REC system piping (14-inch diameter), the normal SW flowrate was 3500 gpm and the normal flow velocity was 8.3 feet/second. The SW flow rate through the REC system following an accident was 400 gpm (as specified in theUpdated Final Safety Analysis Report), and the accident flow velocity was 0.9 feet/second. The inspectors noted that the flow velocity of SW to the REC systemwas less than the flow velocity above which significant accumulation of sand due to settling should not occur. The SW sedimentation study concluded that "a flow velocity of 1.1 feet/second or more will prevent significant accumulation from occurring." Thus,the calculated postaccident SW flow velocity through the REC system was less than theflow velocity at which sediment typically found at Cooper Nuclear Station would no longer be entrained. Additionally, the sediment found within the SW system was knownto be greater than a median size of 0.4 mm and, consequently, the potential fordeposition in the system was greater. The inspectors also reviewed REC HXperformance test data for SWP A REC HX since 1999 and found evidence that the REC HXs had a relatively low amount of margin to withstand sedimentation buildup. Data reviewed for 33 quarterly tests performed on the SWP A REC HX since 1999 indicated that the HX fouling limit of 0.006 hr*ft 2*F/BTU had been exceeded twice, and that thefouling criteria exceeded 0.005 hr*ft 2*F/BTU on five occasions. This data indicated thatthe performance margin for the REC HXs may be relatively low and could be adversely affected by the deposition of sediment in the HX.In response to the inspectors' concern, the licensee completed an analysis, NEDC 94-021, "REC-HX-A & REC-HX-B Maximum Allowable Case Fouling," in an attempt to bound the adverse effects of the potential buildup of sediment in the REC HXs followingan accident. At the end of the inspection period, the licensee was still evaluating theresults of the analysis. The results are scheduled to be published in an engineering evaluation in June 2006.Analysis. The inspectors determined that further inspection was required to review thelicensee's engineering evaluation and evaluate the potential impact of this issue on the performance of the REC HXs.Enforcement. This issue was identified as unresolved item pending the NRC's review ofthe licensee's evaluation: URI 05000298/2005015-02, Potential for Plugging of RECHeat Exchangers During a Design Basis Accident. 7.Potential Adverse Impact from Debris Loading and Bypassing SW StrainersThe inspectors assessed the impact that the increased debris loading, and operation ofSW with one or more strainers bypassed, has had on safety-related components cooled

by the system. In order to assess the potential effects of silt/sand/debris ondownstream components the inspectors:*Reviewed a list of condition reports over a 5-year time frame with a word search onsand, silt, or sediment. The inspectors reviewed the empirical data and selected 15-20 instances where components were apparently adversely affected. The safety function for the components identified in the list was then reviewed for potential impact.

-14-*Assessed whether SW flow would entrain and/or deposit material within thesystem. *Evaluated whether transported sediment/debris could adversely effect downstreamcomponents, especially those components not known to have been previously affected. The inspectors reviewed a list of critical tolerances in the SW system against known debris size.*Compared a list of strainer bypassing evolutions over the past 5 years with HXfouling factors to determine if there was a relationship between bypassing the strainer and a reduction in HX performance (e.g., higher HX fouling factors).The inspectors did not identify instances in which safety-related equipment wasadversely impacted by the introduction of larger debris into the SW system due tooperating with the SW strainers bypassed. However, the inspectors noted that largerocks approximately 4 inches in diameter were removed from one of the strainers duringthe week of November 7, 2005. Given the presence of the large rocks found in the SWstrainer, and the history of debris in the SW intake bay, the inspectors did note that the potential for adverse effects on downstream components remained.8.Causes of Increased Debris LoadingThe inspectors reviewed trends associated with changing conditions in the MissouriRiver in order to determine if there was a correlation between the changing conditions and the increase in SW system debris loading at Cooper Nuclear Station in recentyears.The inspectors noted that the river level was approximately 877 feet mean sealevel (MSL) in 2004 and 2005 when both of the SW debris events occurred. The inspectors also observed that the time frames during which these sedimentation eventsoccurred were following the end of the navigation season (14 days in the case of the October 2005 event). The inspectors also noted that a significant majority (29 of 40) of the SW strainer high DP events occurred at night. The inspectors could not attribute this fact to any particular factor (lower river temperature, cycling of the spargers, etc.).The inspectors could not definitively attribute the cause of the increased sedimentationto be the lower river levels. However, the inspectors observed that, due to the construction of the weir wall in front of the intake structure, more river water must make a sharp turn in order to enter the intake structure when river level is low. Below a river level of 885 feet MSL, more water must go around the wall versus over it, and at 867.5 feet MSL, all of the water must go around the weir wall. This larger volume of water "turning the corner" resulted in a higher fluid velocity in front of the intake structure and appeared to cause greater entrainment of sand/sediment. This observation was confirmed by the Computational Fluid Dynamic studies that the licensee had performedand Section B-2, 1973 CNS Silting Study - Part III of Final Safety Analysis ReportAmendment 31. A primary cause of the lower river level has been the drought conditions in the Missouri River valley.

-15-Following the November 2004 event, the licensee cleaned the SW intake bay to removethe sediment. Sediment levels downstream of the traveling screen were then measured every other day to evaluate the effectiveness of the cleaning. The sediment levels returned to an equilibrium state after 16 days. The sediment pattern was similar toprevious trends: the highest sediment levels were at the traveling screen and decreased to near zero levels at the J4B and J4C sparger header locations.9.Industry Operating Experience

a. Inspection Scope

The inspectors reviewed various NRC generic communications and operatingexperience from other licensees relevant to SW and intake structure challenges.

Specifically, the inspectors reviewed Generic Letter (GL) 89-13, "Service Water System Problems Affecting Safety-Related Equipment," and the licensee's associated response letter for actions related to the accumulation of sediment/debris in the intake structure.

b. Findings

Introduction.

The inspectors identified a Green finding for the licensee's failure toimplement a commitment made to the NRC. Specifically, the licensee did not carry outthe programmatic SW intake bay inspections described in their response to NRC GL 89-13 "Service Water System Problems Affecting Safety-Related Equipment."Description. The NRC issued GL 89-13, "Service Water System Problems AffectingSafety-Related Equipment," on July 18, 1989. The GL was written to require licensees to supply information about their respective SW systems to assure compliance with theGeneral Design Criteria (GDC) of 10 CFR Part 50, Appendix A. Specifically, licensee responses were evaluated against GDC 44, "Cooling Water;" GDC 45, "Inspection of Cooling Water System;" and GDC 46, "Testing of Cooling Water System." GL 89-13 requested licensees to implement controls in five recommended topical areas to ensure compliance with the GDCs and required licensees to advise the NRC whether therecommendations in each of the five areas had been implemented and provide a schedule for completion for those actions still being implemented.Recommendation III of GL 89-13 required licensees to "ensure by establishing a routineinspection program . . . that corrosion, erosion, protective coating failure, silting, and biofouling cannot degrade the performance of the safety-related systems supplied byservice water." In their response to the GL dated January 29, 1990, the licensee statedthat "The present intake structure inspection includes examination of the basin for silt, debris and deterioration (including corrosion) and frequent monitoring of silt levels. The deterioration inspection is performed by using divers or dewatering the bay."In 1994 the NRC Service Water System Operational Performance Inspection teamnoted that the inspections had not been performed but that the licensee intended toimplement modifications to the plant to allow such inspections to be conducted in the future. The NRC inspection team documented in NRC Inspection Report05000298/1994-004 the licensee's intent to make changes to the plant to allow direct inspections of the SW intake bay by divers. In September 1995, the licensee proposed

-16-five alternatives to modification and the plant modification was subsequently cancelled. The licensee instead relied upon direct inspections of the circulating water bays to make educated assessments of the conditions that may be expected in the SW bay. Thelicensee did not implement an inspection program for the SW intake bay as described in their response to GL 89-13.In September 2003 a licensee self-assessment of the "Heat Exchanger GL 89-13Program" identified that the "basis for cancelling the implementation of a plannedmodification" was "not clearly documented." The condition report written at that time incorrectly concluded that the statement in the licensee's GL 89-13 response was not infact a commitment. The condition report was closed without any corrective action being proposed.The inspectors verified that no diving or dewatering of the SW intake bay downstream ofthe traveling water screens had ever been performed. The inspectors reviewed records of the limited inspections that had been performed upstream of the traveling water screens and downstream of the screens in the area above the waterline. These inspections were limited in scope and did not meet the full intent of GL 89-13.

Additionally, the inspectors were unable to identify any correspondence to the NRC thatshowed that the licensee had changed or cancelled the commitment contained in theJanuary 29, 1990, response to GL 89-13.The inspectors noted that numerous foreign objects have been identified in the intakebay and/or ingested into the SW system that could have been identified and removedduring physical inspections. These items have included large rocks and pieces ofcorroded metal that have migrated into the SW system.Analysis. The inspectors considered the failure to meet a commitment as aperformance deficiency. The finding was more than minor since the failure to perform inspections could become a more significant safety concern if left uncorrected.

Degraded conditions in the SW intake bay could affect the operability of the ultimateheat sink for the facility. This finding is not suitable for significance determinationprocess evaluation, but was reviewed by NRC management and determined to be ofvery low safety significance due to the fact it did not result in an increase in the likelihood of an initiating event and did not result in the actual degradation of a mitigating system. The inspectors identified crosscutting aspects in problem identification andresolution, in that this issue was identified by the NRC in 1994 and again by the licenseein 2003 without any corrective actions being taken.Enforcement. No violation of NRC requirements was identified. The licensee enteredthis finding into their corrective action program as CR-CNS-2005-8576. This finding is identified as FIN 05000298/2005015-03, Failure to Implement Commitment in Response to Generic Letter 89-13.10.Potential Generic IssuesThe inspectors did not identify any potentially generic issues related to the SW event.

-17-4OA6 Meetings, Including ExitOn March 14, 2006, the results of this inspection were presented to Mr. S. Minahan andother members of his staff who acknowledged the findings. The inspector confirmed that the supporting details in this report contained no proprietary information.ATTACHMENT:

SUPPLEMENTAL INFORMATION

KEY POINTS OF CONTACT

Licensee Personnel

D. Buman, Assistant System Engineering Manager

R. Edington, Vice President

R. Estrada, Corrective Actions Manager

J. Flaherty, Site Regulatory Liaison

P. Fleming, Licensing Manager

G. Kline, Director, Engineering

S. Minahan, General Manager of Plant Operations

J. Roberts, Director, Nuclear Safety Assurance

D. Vorpahl, Engineer, Service Water SystemNRC Pers onnel

S. Schwind, Senior Resident Inspector

LIST OF ITEMS OPENED, CLOSED, AND DISCUSSED

Opened

05000298/2005015-02URIPotential for Plugging of REC Heat Exchangers During aDesign Basis Accident (Section 4OA5.6)

Closed

05000298/FIN-2005002-09URIBoth SW Discharge Strainers Clogged Due to Silt Intrusion(Section 4OA5.3)

Opened and Closed

05000298/2005015-01NCVInadequate Corrective Actions for SW Strainer CloggingEvents (Section 4OA5.3)05000298/2005015-03FINFailure to Implement Commitment in Response to GenericLetter 89-13 (Section 4OA5.9)

1A1-2LIST OF ACRONYMSDPdifferential pressure

CFRCode of Federal RegulationsFINfinding

GDCGeneral Design Criteria

GLgeneric letter

HXheat exchanger

LOSWloss of service water

MSLmean sea level

NCVnoncited violation

NRCU.S. Nuclear Regulatory Commission

psidpounds per square inch differential

psigpounds per square inch gage

RECreactor equipment cooling

RHRresidual heat removal

SWservice water

SWPservice water pump

URIunresolved item

LIST OF DOCUMENTS REVIEWED

System Operating Procedure 2.2.3.1, "Traveling Screen, Screen Wash, and Sparger System"Missouri River Level Trend Data from 1994 to 2005

Plots of Service Water Differential Pressure on August 5, 2005, and October 18 to October 21, 2005Sounding Level Information for SW Intake Bay from November 15, 2004, until November 18, 2005"The Evaluation of Thermal Effects in the Missouri River Near Cooper Nuclear Station," datedApril 1972 - March 1973Records of Heat Exchanger Testing and Maintenance from 1999 - 2005, for Both Trains ofDiesel Generator Jacket Water, Diesel Generator Lube Oil, Diesel Generator Intercooler,Residual Heat Removal, Reactor Equipment Cooling, and Turbine Equipment Cooling Heat ExchangersEngineering Evaluation 03-003, "Reconstitute and Define the Design Basis of the ServiceWater Pump Discharge Strainers," Revision 2Updated Safety Analysis Report, Sections 4.0, 8.0

Technical Specification 3.7.2

Control Room Log Entries, Queried for "Zurn," "Sedimentation," and Debris

1A1-3Condition ReportsCR-CNS-2001-2541CR-CNS-2002-3018CR-CNS-2003-5062CR-CNS-2004-7464CR-CNS-2001-5373CR-CNS-2002-3901CR-CNS-2004-1615CR-CNS-2005-5138

CR-CNS-2001-6337CR-CNS-2002-4467CR-CNS-2004-4046CR-CNS-2005-6714

CR-CNS-2002-0373CR-CNS-2003-0046CR-CNS-2005-5682CR-CNS-2005-7772

CR-CNS-2002-1376CR-CNS-2003-0271CR-CNS-2004-7408CR-CNS-2005-7747

CR-CNS-2002-1387CR-CNS-2003-2488CR-CNS-2004-7409CR-CNS-2005-8227

CR-CNS-2002-2467CR-CNS-2003-4936CR-CNS-2004-7415CR-CNS-2005-8576NPPD Letter to the NRC, "Generic Letter 89-13 Recommended Inspection Program," datedOctober 15, 1990Operational ExperienceOperational Experience-15108, Silt Levels in Main Intake Structure Exceed Allowable Values Operational Experience-16024, Excessive Buildup of River Sediment Results in Reduced WaterDepth Outside Plant Intake Structure

2A2-1November 2, 2005MEMORANDUM TO:John Hanna, Senior Resident InspectorDivision of Reactor ProjectsFROM:Kriss M. Kennedy, Chief, Projects Branch CDivision of Reactor Projects SUBJECT: SPECIAL INSPECTION CHARTER TO EVALUATE SERVICE WATER EVENTAT COOPER NUCLEAR STATIONIn response to an event that led to the inoperability of the service water system at C

ooperNuclear Station on October 20, 2005, a Special Inspection is being chartered.

You are herebyassigned to conduct the Special Inspection.

Nick Taylor, Resident Inspector, Cooper Nuclear Station, has been assigned to assist you during this inspection.A.BasisOn October 20, at 0909 with Service Water Pumps A, B, and C running, operatorsstarted Service Water Pump D.

Following the start of Service Water Pump D, at 0910, the control room operators received a high differential pressure alarm on Service Water Strainer B followed by a high differential pressure alarm on Service Water Strainer A.

Both service water cross-connect valves (SW-MO-36/37) closed on low service water header pressure.

Operators observed that the service water header pressure in Loop A

was approximately 42 psig and 15-20 psig in Loop B.

The differential pressure across Service Water Strainer A peaked at 20 psid and recovered in approximately 3 minutes following the automatic initiation of strainer backwash.

The differential pressure across Service Water Strainer B peaked at 20.9 psid, however, the automatic initiation of backwash did not result in a sufficient decrease in differential pressure and operators bypassed the strainer.

Following these actions, the service water system headerpressures returned to normal.

During the event, operators declared both loops of service water inoperable due to exceeding the strainer differential pressure structural integrity limit of 15 psid.

With both loops of service water inoperable, operators declared both emergency diesel generators inoperable.The high differential pressure across the strainers was the result of debris (small rocks)which was introduced into the service water system following the start of Service WaterPump D.

The high debris loading clogged the strainers.

Cooper Nuclear Station experienced a similar event in November 2004, and has experienced other challenges to the proper operation of the service water system resulting from debris over the lastseveral years. Management Directive 8.3, "NRC Incident Investigation Program," was used to evaluatethe level of NRC response for this event.

In evaluating the deterministic criteria of

MD8.3, it was determined that introduction of debris into the service water system: (1) led tothe loss of a safety function or multiple failures in systems used to mitigate an actual event, and (2) involved repetitive failures or events involving safety-related equipment or

2A2-2deficiencies in operations.

Since the deterministic criteria was met, the service waterevent was event was evaluated for risk.

The preliminary Estimated Conditional Core Damage Probability was determined to be between 2.0E-6 and 2.0E-5.

In accordancewith MD 8.3, the results of the risk assessment indicates that NRC response to thisevent falls between the overlap region to conduct a Special Inspection and no additional inspection, and the region that requires a Special Inspection. Region IV has reviewed the results of the MD 8.3 evaluation and determined that aSpecial Inspection is warranted.

Based on previous inspections of these issues, and inspection that has occurred since the October 20 event, the following specific concerns have been identified that warrant further inspection and assessment:*The timeliness and adequacy of corrective actions that Cooper Nuclear Stationhas already implemented or plans to implement to correct the cause of these events*The adequacy of Cooper Nuclear Station's interim compensatory measures toprevent challenges to the service water system while the longer term correctiveactions are being implemented*The assumptions and basis used by the licensee to evaluate the ability of theservice water system to continue to meet design requirementsThis Special Inspection is chartered to identify the circumstances surrounding this event, determine if the licensee's long-term corrective actions are timely and adequate, and to determine if the licensee's interim compensatory actions are adequate.B.ScopeThe inspection is expected to perform data gathering and fact-finding in order toaddress the following:14.Develop a complete description of the service water event that occurred onOctober 20, 2005, and a complete sequence of events, including operator and system response, rela ted to the event.15.Develop a list of similar challenges to the service water system resulting fromdebris and actions taken by the licensee to correct the problem.16.Identify and evaluate the adequacy and timeliness of the licensee's long-termcorrective actions established prior to the event on October 20, 2005, and any changes following the event, to address the adverse impact of debris on the service water system. 17.Identify and evaluate the adequacy of the licensee's compensatory measuresestablished prior to the event on October 20, 2005, and following the event, toaddress the adverse impact of debris on the service water system. 18.Identify and assess additional actions planned by the licensee in response to thisevent, including the timeline for their completion of these actions.

2A2-319.Evaluate the assumptions and basis used by the licensee to determine the abilityof the service water system to continue to meet design requirements.20.Assess the impact that the increased debris loading, and operation of the servicewater system with one or more strainers bypassed, has had on safety-relatedequipment cooled by service water.21.Identify the changing conditions that have resulted in the increase in servicewater system debris loading in recent years.22.Compare the results of your inspection with the licensing and design basis forCooper Nuclear Station. 23.Evaluate pertinent industry operating experience to the event, including theeffectiveness of any action taken in response to the operating experience.24.Determine if there are any generic issues related to the service water event. Promptly communicate any potential generic issues to regional management.25.Assess the safety significance of any inspection findings.

C.GuidanceInspection Procedure 93812, "Special Inspection," provides additional guidance to beused by the Special Inspection Team.

Your duties will be as described in InspectionProcedure 93812.

The inspection should emphasize fact-finding in its review of the circumstances surrounding the event.

It is not the responsibility of the team to examine the regulatory process.

Safety concerns identified that are not directly related to theevent should be reported to the Region IV office for appropriate action.You will formally begin the special inspection with an entrance meeting to be conductedno later than November 7, 2005.

The inspection will include a review of the results ofthe licensee's root cause analysis.

You should brief Region IV management during the course of your inspections and prior to your exit meeting.

A report documenting the results of the inspection should be issued within 30 days of the completion of the inspection.This Charter may be modified should you develop significant new information thatwarrants review.

Should you have any questions concerning this Charter, contact me at

(817) 860-8144. cc via E-mail:B. Mallett

T. Gwynn

J. Dixon-Herrity

A. Howell

2A2-4D. Chamberlain

A. Vegel

K. Kennedy

V. Dricks

W. Maier

W. Walker

D. Terao

B. Benney