IR 05000298/1999005

Insp Rept 50-298/99-05 on 990502-29.Noncited Violations Identified.Major Areas Inspected:Operations,Maint, Engineering & Plant Support

ML20196E151
Person / Time
Site:	Cooper
Issue date:	06/16/1999
From:	NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION IV)
To:
Shared Package
ML20196E148	List: IR 05000298/1999005 ML20196E141
References
50-298-99-05, 50-298-99-5, NUDOCS 9906280089
Download: ML20196E151 (16)

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ENCLOSURE 3 U.S. NUCLEAR REGULATORY COMMISSION

REGION IV

Docket No.: 50-298 License No.: DPR 46 Report No.: 50-298/99-05 Licensee: Nebraska Public Power District Facility: Cooper Nuclear Station Location: P.O. Box 98 Brownville, Nebraska Dates: May 2-29',1999 Inspectors: M. Miller, Senior Resident inspector W. McNeill, Reactor inspector, Engineering and Maintenance Branch C. Clark, Reactor Inspector, Engineering and Maintenance Branch G. Pick, Senior Project Engineer, Branch E J. Spets, Resident inspector, Washington Nuclear Project C. Paulk, Regional Inspector, Maintenance Branch Approved By: C. Marschall, Chief, Project Branch C ATTACHMENT: SupplementalInformation l

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9906280089 990616 PDR ADOCK 05000298 0 PDR ;

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EXECUTIVE SUMMARY Cooper Nuclear Station NRC Inspection Report No. 50-298/99-05 Operations

• Control room operators identified a faulted main turbine pressure controller. They successfully demanded that maintenance and engineering evaluate, troubleshoot, and repair the problem while online. The simulator staff trained four operations crews on manual control of turbine pressure, prior to taking their watches. Operators manually controlled reactor pressure when technicians removed the faulted transmitter and when they replaced it (Section 01.1).

• In response to REC system leakage, engineers identified and corrected some of the leak paths. Er'gineers developed inventory calculations that effectively supported system operability (Section O2.1).

Maintenance

• Technicians performed work in a step-by-step fashion as required by procedures. They coordinated their activities with the control room staff, and operators followed procedures as required. Equipment met procedural acceptance criteria (Section M1.1).

• Utility and mechanical maintenance technicians initiated over 40 well focused problem identification reports during the past 2 months. For example, a mechanical maintenance technician initiated a problem report when maintenance technicians were instructed to elongate bolt holes, but engineers had not evaluated the change to the plant. This is an improvement in self-critical and insightful problem identification by mechanical and utility maintenance staff (Section M7.1).

Inspectors will close Licensee Event Report 99-03 regarding the failure to test a service water valve after maintenance. This licensee identified Severity Level IV violation meets the noncited violation enforcement criteria (Followed by SCR 99-0284)(Section M8.1).

Enaineerina

• The licensee actions to address Year 2000 issues are in process. The inspector

. reviewed selective samples of these activities and found no significant concerns

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• Inspectors reviewed the engineering activities to evaluate and correct plant

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vulnerabilities similar to those that caused flooding at a similar plant. For the sample inspected, the evaluations and modifications appeared appropriate (Section E7.1). I i

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. * During concurrent suppression pool cooling and torus water transfer, the residual heat removal system would not have been able to perform its low pressure injection functio Prior to implementation of the improved Technical Specifications, the operating procedures for transferring torus water to the radwaste system concurrent with suppression pool cooling had not required that the affected residual heat removal system be declared inoperable. This condition was a violation of 10 CFR Part 50, Appendix B, Criterion V, which is being treated as a noncited violation, consistent with Appendix C of the NRC enforcement policy (Section E8.3).

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Report Details Summarv of Plant Status The plant was at 100 percent power at the beginning of this report period. On May 19,1999, power was reduced to 68 percent to troubleshoot and test inbowd Main Steam Isolation Valve A. The valve operated satisfactorily and the plant was returned to full power. On April 27 and May 8, power was reduced to 97 percent. Operators placed the main turbine digital electrohydraulic control system in manual control for about 45 minutes. Operators removed a failing pressure controller transmitter from service during the April 27 evolution and installed a new transmitter in it's place during the May 4 evolutio I. ODerations 01 Conduct of Operations 01.1 Control Room Crew Problem Solvina Effectiveness Insoection Scoce (71707)

The inspector observed operator identification, assessment, and intervention of turbine pressure control anomalies and other concerns. The inspector observed multiple plant

-. discussions, meetings, and control room activities to diagnose and correct the controller problem and other problem Observations and Findinas in several cases, the operators observed plant indications closely, resulting in identification of equipment problems before they impacted operations. In resolving the issues, operators demanded coordination and assistance from plant organization Managers met with plant and engineering staff members to prioritize and address the concern The most significant example occurred when control room operators noted that the backup controller for the main turbine pressure control had drifted up in pressure setting to the point where it took over control from the primary controller. After slowly drifting upward approximately 4 pounds from its initial setting, the drifting controller took over pressure control, stabilized, and maintained pressure control satisfactorily. The former

- primary controller remained stable in a backup mode. Engineers, maintenance technicians, and operators reviewed the behavior of the controllers and determined that immediate contingency planning was necessary should the faulted controller demonstrate further anomalous behavior. Operations, maintenance, and engineering management addressed various contingencies associated with the potential failure of the controller and the need to place the turbine controller in manua The existing procedure for turbine control required that for one faulted or disabled controller operators reduce power to 25 percent. Cooper based the requirement on a General Electric Service information Letter (SIL) that described a problem that occurred at another nuclear plant. The SIL stated that analysis had determined that thermallimits

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-2-might be exceeded for loss of pressure control. Consistent with this Sll, Cooper procedures required reduction of power to 25 percent or less if one of the two control channels failed. Since the channel had not failed, but was behaving in an unusual way, the licensee discussed this with General Electric and found that they had provided a revision of the SIL. This revision concluded that the licensee could have operated the plant with only one controller in service between 90 and 100 percent power or between zero and 25 percent power. General Electric had not analyzed the range between 25 and 90 percent power for the transient associated with a single controller failur Cooper changed the procedure to allow operation consistent with the SI The contingencies provided in the procedure gave operating bands where the controller would riot be considered faulted. It also provided that, outside cf the bands, operators should consider the controller faulted. For this condition, the opeators should disable the controller by placing pressure controlin manual and removing the faulted transmitter from service. Several operating crews trained in the simulator to review and practice operation of manual pressure control before taking the watch with the potentially faulted controller. The operators changed turbine control from automatic to manual: to remove the transmitter from service and to return the transmitter to service after it had been replaced. Manual turbine pressure control was successful and operators returned control to the automatic system within approximately 40 minutes on both occasion The licensee sent the faulted transmitter to the vendor for diagnosi Conclusions Control room operators identified a faulted main turbine pressure controller. They

.successfully demanded that maintenance and engineering evaluate, troubleshoot, and repair the problem while online. The simulator staff trained four operations crews on manual control of turbine pressure, pric to taking their watches. Operators manually controlled reactor pressure when technicians removed the faulted transmitter and when they replaced i O2 Operational Status of Facilities and Equipment O2.1 Operability Evaluation of Reactor Eauipment Coolina (REC) System Leakaae Insoection Scooe (71707)

Inspectors reviewed the basis for operability for the REC system with higher than anticipated leakage, inspectors also reviewed actions to reduce the leakage, Observaticas and Findinas Operators noted that the REC surge tank level had dropped and asked engineering to determine the source of leakage. The engineers found some of the leakage and restored normal surge tank operatio *

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-3-The REC system is a closed loop cooling system for essential equipment. The inspectors reviewed (PIR) 4-01668 on abnormally high leakage from the system. The leakage of the REC system was 0.875 inch of surge tank water level per day (6-7 gallons per day). The licensee had established in calculation NEDC 98-002 that leakage of up to 1.32 inches per day could be tolerated and that with such leakage the REC system would remain operable for the designed postaccident mission time of 30 days. The inspectors reviewed the calculation and verified the pump net positive suction head, line losses, and instrument errors were properly accounted for in the calculation. The inspectors concluded that the engineers satisfactorily supported operability of the REC syste Conclusions In response to REC system leakage, engineers identified and corrected some of the leak paths. Engineers developed inventory calculations that effectively supported system operabilit Miscellaneous Operations issues O8.1 {QLosed) Unresolved item 98022-02: Performance of special tests without a documented safety evaluation. Indpectors found a program vulnerability but no significant performance based examples. Therefore, this item is closed based on it's low significance and it's inclusion in the licensee's corrective action program as PIR 3-4034 II. Maintenance M1 Conduct of Maintenance M1.1 Maintenance and Testina Observation inspection Scope (61726) i

The inspectors observed portions of the following maintenance and surveillance activities:

Procedure 6.2DG.101 Diesel Generator 31-Day Operability Test, Revision 14 C5 Procedure 6.2ARI.701 ARl/ATWS/RPT Low-Low and PCIS Low-Low-Low Reactor Water Level Channel Functional Test (DIV 2),

Revision 0 Procedure 6.PAM.302, Postaccident Monitoring Drywell Pressure Instrumentation Calibration Test, Revision 3

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--4-1 . Observations and Findinas Technicians performed work instructions step by step with only minor errors. Packages for the work were complete and provided requirements for plant configuration, health physics, postmaintenance testing, operability, and system restoration. Acceptance

. criteria were consistent with Technical Specifications and were. met during the activitie Technicians observed quality assurance requirements and followed quality control observations when required. Supervisors were presat for portions of the activitie Operators performed surveillance tests consistent with procedural requirements with good communications and few minor error Conclusions Technicians performed work in a step-by-step fashion as required by procedures. They coordinated their activities with the control room staff, and operators followed procedures as required. Equipment met procedural acceptance criteri M7 Qua.'Ity Assurance in Maintenance Activities M7.1 Initiation of Strona PIRs Scooe (61707)

Inspectors reviewed daily PIRs and held discussions with maintenance technicians and supervisor Observations and Findinas Utility and mechanical maintenance technicians had not initiated many PIRs prior to ,

March 1999. Of those they initiated, most involved documentation of self-revealing equipment failures and process problems which stopped work. In these cases, work could not be continued unless a report was generated. Most reports were not self-critical or insightful. . Since March 1999, mechanical and utility maintenance technicians and supervisors have initiated over 50 problem reports identifying many problems of a self-critical or probing nature. About 40 have been initiated over the past 2 months. An ;

' example of an improved PIR documented a lack of an engineering analysis to support a )

work package that allowed technicians to elongate bolt holes on a flange. As a result of i the improved problem identification reporting, the technicians identified several

. engineering issues and maintenance process weaknesses. Interviews with

- maintenance staff and supervisors indicated that supervisory expectations for problem identification and questioning attitude had been strongly reinforce i

' . Conclusion

- Utility and mechanical maintenance technicians initiated over 40 well focused PIRs during the past 2 months. For example, a mechanical maintenance technician initiated

' a PIR when technicians were instructed to elongate bolt holes, but engineers had not

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evaluated the change to the plant. This is an improvement in self-critical and insightful problem identification by mechanical and utility maintenance staf M8 Miscellaneous Maintenance issues (92902)

M8.1 (Closed) Licensee Event Report 50/298-99003-00: Missed Postmaintenance Test of Air-Operated Service Water Valve. The work instructions failed to require an appropriate test to return the valve to operability. Failure to provide instructions appropriate to the circumstances is a violation of 10 CFR Part 50, Appendix B, ;

Criterion V (50-298/99005-01). This licensee event report documents a violation of NRC 1 requirements and is entered in the licensee's corrective action program as SCR 99-0284. This Severity Level IV violation is being treated as a noncited violation consistent ;

with Appendix C of the NRC Enforcement Polic M8.2 (Closed) Inspection Followuo item 50-298/9716-01: problems encountered in i erosion / corrosion monitoring program. During a previous inspection, the NRC found that the licensee experienced problems implementing the long-term erosion / corrosion !

monitoring program as a result of frequent program staffing turnovers. The NRC l I

observed similar problems, erroneous calculations, and incomplete engineering component evaluation forms during review of the Refueling Outage 17 erosion / corrosion activities performed in 199 The licensee documented and evaluated some of these identified erosion / corrosion problems in PIR 2-1212489, PlR 2-15918, PIR 2-13389, Sirnificant Condition Adverse to Quality 97-0803, and Condition Adverse to Quality 97-0681. All Refueling Outage 17 erosion / corrosion inspection and evaluation packages were reviewed for errors and j corrective actions were implemented. The inspector reviewed the identified corrective !

and preventive actions, along with the associated documents, and considered these l actions satisfactory to address the erosion / corrosion problems identified during l Refueling Outage 1 Ill. Engineering l l

i E2 Engineering Support of Facilities and Equipment E Review of Activities Associated With Computer Systems and Components (Tl 2515/141) Inspection Scope (37551)

The inspector reviewed selective samples of licensee actions to address Y2K issues and found no significant concern Observations and Findinas  !

A region-based reviewer conducted an abbreviated review of activities and documentation associated with assuring the readiness of computer systems and

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-6-components using Temporary Instruction (TI) 2515/141, " Review of Year 2000 (Y2K)

Readiness of Computer Systems at Nuclear Power Plants." The review addressed aspects of Y2K management planning, documentation, implementation planning, initial assessment, detailed assessment, rededication activities, Y2K testing and validation, notification activities, and contingency planning. The reviewer used NEl/NUSMG 97-07,

" Nuclear Utility Year 2000 Readiness," and NEl/NUSMG 98-07," Nuclear Utility Year 2000 Readiness Contingency Planning," as the primary references for this revie The results of this review will be combined with the results of the reviews conducted at the other plants in the nation in a summary report to be issued by July 31,1999, Conclusions The licensee actions to address Y2K issues are in progress. The inspector reviewed selective samples of these activities and found no significant concerns.

E7 Quality Assurance in Engineering E7.1 Operational Experience Scoce (37551)

Inspectors reviewed Resolve Condition Report (RCR) 2-24333 that addressed the potential for flooding the reactor building by exceeding fire protection system operational limits. The inspectors reviewed operational event reports and corrective action summaries associated with the concern and inspected systems associated with the concern, Observations and Findinas During plant tours, the inspectors noted that the licensee had hung temporary test tags at the top of each of the fire protection header risers in the reactor building. The inspectors found that the licensee had initiated RCR 2-24333 in response to a flooding event at Washington Nuclear Project-2. The flooding event resulted from failure of a 12-inch fire protection riser isolation valve. The licensee recognized their system was similar, initiated the RCR, and initiated steps to mitigate this issue. The licensee implemented a temporary modification that placed nitrogen gas pockets at the top of i each riser, which would absorb and dampen any pressure waves that occurred as a i result of pump starts. Other corrective actions that the licensee implemented included monitoring the size of the gas pockets to determine whether they remained constant, Conclusion inspectors reviewed the engineering efforts to evaluate and correct plant vulnerabilities similar to those that caused flooding at a similar plant. For the sample inspected, the evaluations and modifications were appropriat F

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-7-E8 Miscellaneous Engineering lasues (92903) )

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E8.1' ' (Closed) Insoection Followuo item 50-298/97201-29: Design bas.is for REC discharge header pressure and time delay setpoints. Inspectors evaluated the two issues for this item that were reviewed in NRC Inspection Report 50-298/98-15: (1) header low setpoint of 55 psig did not have a documented basis and (2) relay delay setpoint of 40 seconds was judged acceptable based on an incorrect criterion. NRC Inspection Report 50-298/97-201 documented that both of these issues were entered into the

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licensee's corrective action program as PIR 20638. NRC Inspection Report 50-298/98-15 documented the review of the planned corrective actions and found them acceptabl The licensee revised calculation NEDC 92-050AC, the last of the corrective actions to be implemente E8.2 (Closed) Licensee Event Report 50-298/96009-03: Appendix R Safe Shutdown Analysis ,

vulnerabilitie )

' As part of its 10 CFR Part 50, Appendix R, reevaluation effort, the licensee identified items that did not have acceptable coping strategies. The licensee issued Revision 0 of Licensee Event Report 96-009 on August 26,- 1996, and the issues identified were reviewed in NRC Inspection Report 50-298/96-25. The inspectors reviewed the licensee's findings at that time, verified that corrective actions had been implemented to eliminate the vulnerabilities, and identified a noncited violation for the reported problem . Revision 0 of the licensee event report identified that the Appendix R reevaluation effort was continuing, additional licensee event report supplements would be submitted as necessary, and the root cause of these Appendix R issues was still under investigatio The report was submitted in abstract form only and did not contain a narrative description as required by 10 CFR 50.73(b)(2). This was acceptable at that time because the reevaluation effort was still in progress. The licensee also identified a commitment that it would submit a final, non-abstract supplement to the licensee event report following completion of its Appendix R re-analysi The licensee issued Revisions 1 and 2 of Licensee Event Report 96-009 in an abstract )

- form and the issues identified in Revisions 0,.1, and 2 were reviewed and closed in NRC

' Inspection Report 50-298/98-15 as a licensee-identified and corrected violation. The i licensee completed its Appendix R re-analysis and issued Revision 3 of Licensee Event Report 96-009 on June 1,1998.' The inspector reviewed Revision 3 of Licensee Event

- Report 96-009 and found the report contained a nonabstract, narrative description of the event, tause, and corrective actions. The inspector identified no additional violation l E8.3 r : (Closed) Inspection Followuo item 50-298/97201-08: Suppression pool transfer to radwast l Observations i

Licensee Memorandum NLS960208 provided that, for a transfer of torus water to l radwaste while in the suppression pool cooling mode, that did not result in an extension i

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-8-of the normal time in the suppression pool cooling mode, low pressure coolant injection (LPCI) could be assumed operable. However, Procedure 2.2.69.3, " Residual Heat Removal Suppression Pool Cooling and Containment Spray," and Procedure 2.2.69, " Residual Heat Removal System," did not include any such restriction on suppression pool water transfer for cleanup to ensure it is coincident with normal suppression pool cooling. Control room logs for the month of July 1997 indicate the residual heat removal system was in operation for approximately 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> to support torus deanup activities with transfer of torus water to the radwaste system.

i The inspector reviewed licensee Memorandum NLS960208," Operability of LPCI During Suppression Pool Cooling Mode," dated October 2,1996. The last paragraph of Memorandum NLS960208 noted that licensing planned to pursue the operability of LPCl during the suppression pool cooling mode further during its evaluation of Condition Adverse to Quality 96-0846 and with the development of the Improved Technical Specification position on this issu Operations personnel identified that as of January 7,1999, in accordance with the improved Technical Specification and Revision 18 of Procedure 2.2.69.3, they declared the LPCI system inoperable when they placed the residual heat removal system in the suppression pool cooling lineup. The inspector reviewed Procedure 2.2.69.3, " Residual Heat Removal Suppression Pool Cooling and Containment," Revision 18, and other associated documents and found appropriate measures were implemented to resolve this ite Since the procedure for operating the residual heat removal system did not require the action statement to be entered when torus water transfer took place concurrent with operation in suppression pool cooling mode, the procedure was not appropriate to the circumstances. This is a violation of 10 CFR Part 50, Appendix B, Criterion V, which requires procedures to be appropriate to the circumstances (50-298/99005-02, closed).

This Severity Level IV violation is being treated as a noncited violation, consistent with Appendix C of the NRC Enforcement Polic Conclusion During concurrent suppression pool cooling and torus water transfer, the residual heat removal system would not have been able to perform its low pressure injection functio j Prior to implementation of the improved Technical Specifications, the operating I procedures for transferring torus water to the radwaste system concurrent with l suppression pool cooling had not required that the affected residual heat removal i system be declared inoperable. This condition was a violation of 10 CFR Part 50, Appendix B, Criterion V, which is being treated as a noncited violation, consistent with Appendix C of the NRC enforcement polic E8.4 (Closed) Violation 50-298/9815-01: multiple examples of a failure to implement and follow procedures as required by 10 CFR Part 50, Criterion The NRC previously identified six examples of instructions, procedures, or drawings without quantitative or qualitative acceptance criteria for determining that important

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. activities had been satisfactorily accomplished. The violation noted that for three of the violations (A.1, A.2, and A.5) the NRC had concluded that information regarding the reason for violations, the corrective actions taken, and the date when full compliance would be achieved was already adequately addressed on the docket in NRC Inspection Report 50-298/98-15. The three remaining violations (or examples of violations) noted the following:

e Violation A.3 identified that as of November 1997, Procedure 13.17, " Residual Heat Removal Heat Exchanger Performance Evaluation," failed to provide appropriate acceptance criteria for determining that heat exchanger performance was acceptable because it directed that a fouling factor calculated from as-measured data be compared to a fouling factor that was based on design basis accident condition e Violation A.4 identified that as of December 4,1997, Surveillance Procedure 6.OG.601,

" Daily Surveillance Log," Revision 9, did not include appropriate acceptance criteria in that the specified limit of 90 F did not include the instrument uncertainties of Temperature Indicator Mi-TR-3020. As a result, the use of Temperature indicator Mi-TR-3020 could permit service water temperatures to exceed the specified limi * Violation A.6 identified that as of December 1997, the licensee implemented Surveillance Test Procedures 6.1SWBP.101, "RHR Service Water Booster Pump Flow Test and Valve Operability Test (DIV 1)," Revision 4, and 6.2SWBP.101, "RHR Service Water Booster Pump Flow Test and Valve Operability Test (DIV 2)," Revision 4, which were not appropriate for the circumstances. The procedures specified the use of gauges that did not have the proper range. Ashcroft Bulletin DU-1 recommended selecting a gauge with a full scale pressure range of approximately twice the normal )

system operating pressure being measured and that the maximum system operating i pressure did not exceed 75 percent of the selected gauge full scale range. The full scale pressure range of the gauges selected for Pressure Gauges SW-PI-385A through 385D resulted in gauges that did not have over-ranged protection, which could have yielded inaccurate dat During this inspection, the inspector reviewed the licensee's January 27,1999, reply to the Notice of Violation for Violations A.3, A.4, and A.6. In the reply the licensee identified a reason for each violation, identified corrective actions and noted they were in full compliance. The inspector reviewed the identified corrective actions implemented for Violations A.3, A.4, and A.6 along with the associated documents and found them satisfactory to address the specific examples cited in the violation ,

l E8.5 (Closed) Unresolved item 50/298 96024-02: Implementation of Safety Guide 11 l

" Instrument Lines Penetrating Primary Reactor Containment Back-fitting Consideration" l The inspectors found that the licensee's implementation of Safety Guide 11 to control valves in the instrument lines in containment was unclear. The safety guide requires a method of verification for each isolation valve. At the time of this finding, operators used the original Technical Specifications. Since that time, the licensee has implemented ,

Improved Technical Specification .

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-10-For instrument lines penetrating containment with valves which are normally closed during plant operation, Technical Specification 3.6.1.3, " Primary Containment isolation Valves (PCIVs)," requires that operators verify the closed position of these valves at least every 31 days. Procedure 6.2PC.602, Revision 0, "l&C Primary Containment Manual Valve Verification," lists instrument lines penetrating primary containment and requires verification that the respective isolation valves are verified closed by operator This surveillance has been implemented successfully and fulfills the requirement to ensure the valve is closed. For normally open valves the operators set the position of the valves when restoring systems to operable status at the beginning of the cycl After initial positioning, operators do not perform direct verification of the valve positio The NRC inspectors sampled instrument line primary containment isolation valves that are required to be open in order for safety-related instruments to receive inputs from pressure and level sensors within the drywell or reactor coolant system. The inspectors verified that these valves were required to be open to support operation and that the expected indication was available. Therefore this item is close X1 Exit Meeting Summary The inspectors presented the inspection resu!!s to members of licensee management at the exit meeting on June 4,1999. The licensee acknowledged the findings presente The inspectors asked the licensee whether any materials examined during the inspection should be considered proprietary. No proprietary information was identifie .

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. t ATTACHMENT PARTIAL LIST OF PERSONS CONTACTED Licensee D. Buman, Acting Plant Engineering Department Manager J. Burton, Performance Analysis Department L.. Dewhirst, Nuclear Licensing Specialist-C. Gaines, Maintenance Marager M. Kaul, Operations Suppori Group J. McMahan, Work Control Supervisor L. Newman, Acting Licensing Manager J. Peters, Nuclear Licensing and Safety Secretary A. Shievier, Operations Manager J. Swalles, Vice President, Nuclear Energy, NPPD INSPECTION PROCEDURES USED IP 37551: Onsite Engineering IP 61726: Surveillance Observation IP 62703: Maintenance Observation IP 71707: Plant Operations IP 92901: Followup - Plant Operations IP 92902: Followup - Maintenance IP 92903: Followup - Engineering IP 92700: LER - Onsite Review ITEMS OPENED. OPENED AND CLOSED. AND CLOSED Opened and Closed 298/99005-01 NCV (Section *.1)

298/99005-02 NCV - suppression pool transfer to radwaste (Section E8.2) i l

Closed l 298/99-03-00 LER Failure to test a service water valve after maintenance (Section M8.1)

298/97016-01 IFl problems encountered in erosion / corrosion monitoring program (Section M8.2)

298/97201-29:. IFl . Design basis for reactor equipment cooling discharge header pressure and time delay setpoints (Section E8.1)

298/96009-03. LER . Appendix R Safe Shutdown Analysis vulnerabilities (Section E8.2)

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-2-298/97201-08 IFl suppression pool transfer to radwaste (Section E8.3).

298/98015-01 VIO multiple examples of a failure to implement and follow procedures as required by 10 CFR Part 50, Criterion V (Section E8.4)

298/96024-02 URI implementation of Safety Guide 11, " Instrument Lines Penetrating Primary Reactor Containment Back-fitting Consideration" (Section E8.5)

DOCUMENTS REVIEWED Procedures 2.2.6 " Residual Heat Removal Suppression Pool Cooling and Containment,"

Revision 18 6.OG.601 " Daily Surveillance Log," Revision 14 C4 6.1 SWPB.101 " Residual Heat Removal (RHR) Service Water Booster Pump Flow Test and Valve Operability Test (DIV 1)," Revision 5 6.2SWPB.101 " Residual Heat Removal (RHR) Service Water Booster Pump Flow Test and Valve Operability Test (DIV 2)," Revision 5 Reports

" Cooper Nuclear Station 1997 Erosion / Corrosion Summary Report," March 24,1998 Quality Assurance Audit No. 98-04,"Special Programs," April 1,1998 Quality Assurance Audit No. 97-06," Outages," June 10,1997 NEDC-32513," Suppression Pool Cooling and Water Hammer," December 1995 Cooper Nuclear Station Probabilistic Risk Assessment Level 1, dated March 1993 Cooper Nuclear Station IST Basis Document, Revision 2 i

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Problem identification Reoorts  ;

2-12489 2-13389 t 2-15918 2-20638 i 4-01668 4-01730

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-3-4-01731

- Conditions Adverse to Quality 97-0681 )

l Sianificant Condition Adverse to Quality 97-0803 l

Memorandums j NLS960208," Operability of LPCI During Suppression Pool Cooling Mode," dated October 2,1996

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NLS970210, " Operability of LPCI in Torus Cooling Mode," dated November 21,1997 j

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Calculations i NEDC 92-050X NEDC 92-050AC .

NEDC 97-004 -  !

NEDC 98-002  !

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