IR 05000461/1999014

Insp Repts 50-461/99-14 & 50-461/98-12 on 990729-0908.Two Violations Occurred & Being Treated as Ncvs.Major Areas Inspected:Aspects of Licensee Operations,Maint,Engineering & Plant Support

ML20217A752
Person / Time
Site:	Clinton
Issue date:	10/01/1999
From:	NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION III)
To:
Shared Package
ML20217A740	List: IR 05000461/1999014 ML20217A736
References
50-461-98-12, 50-461-99-14, NUDOCS 9910120077
Download: ML20217A752 (40)

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U.S. NUCLEAR REGULATORY COMMISSION REGION lli Docket No:

50-461 License No:

NPF-62 Report Nos:

50-461/99014; 50-461/98012(DRP)

Licensee:

lilinois Power Company Facility:

Clinton Power Station Location:

Route 54 West Clinton, IL 61727 Dates:

July 29 - September 8,1999 Inspectors:

P. L. Louden, Senior Resident inspector K. K. Stoedter, Resident Inspector C. E. Brown, Resident inspector D. E. Zemel, Illinois Department of Nuclear Safety Approved by:

Thomas J. Kozak, Chief Reactor Projects Branch 4 Division of Reactor Projects i

9910120077 991001

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PDR ADOCK 05000461 G

PDR

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EXECUTIVE SUMMARY Clinton Power Station NRC Inspection Report 50-461/99014; 50-461/98012(DRP)

This inspection included aspects of licensee operations, maintenance, engineering, and plant support. The report covers a 6-week period of resident inspection.

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Operations The inspectors determined that operations personnel generally responded to plant a-annunciators in a timely manner, referenced the appropriate annunciator response i

procedures, made sufficiently detailed log entries, and appropriately referenced Technical Specifications and Limiting Conditions for Operation when necessary.

However, the inspectors identified a Non-Cited Violation for a discrepant control board indication which had gone unnoticed by control room operators for 7 hours8.101852e-5 days <br />0.00194 hours <br />1.157407e-5 weeks <br />2.6635e-6 months <br />. This q

illustrated the need for continued improvement in the areas of control board monitoring i

and shift turnovers (Section 01.1).

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The inspectors' query prompted the licensee to identify that control room operators were

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referencing the wrong channel for off-gas system release rates, initially, operations management only addressed the issue intemally with all operators. Later, a condition i

report was written for trending purposes. Based on discussions with the inspectors, the licensee decided that the classification would be raised to a higher level to ensure the extent of condition of this issue was evaluated regarding differences between simulator

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and main control room instrument settings (Section 01.2).

The inspectors concluded that the licensee's management of time spent in Limiting

Conditions for Operation associated with three maintenance activities was effective.

i However, a poor maintenance practice during an emergency diesel generator outage resulted in an unnecessary delay in completing the outage, As a result, about 90 percent of the allowed outage time was expended for the outage (Section 01.3).

The inspectors concluded that the standby gas treatment system was appropriately

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tested and maintained and that online maintenance was well-managed to ensure it was completed within the scheduled outage time (Section O2.1).

The inspectors determined that although the total number of out-of-service annunciators

had slowly increased since plant restart, improvements had been made in the management of the out-of-service annunciator program (Section 02.2).

Maintenance The inspectors and the licensee have identiced multiple examples of deficiencies with

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maintenance procradures over the last 3 months. The procedure deficiencies have caused equipment problems and plant transients that have unnecessarily challenged operations personnel.' A broad scope review of maintenance procedures had not been initiated and was not planned to be completed until the end of 1999 (Section M3.1).

One Non-Cited Violation was identified regarding inadequate procedures which were

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used for equipment control during fix-it-now team activities (Section M3.2).

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Enaineerina Inspector prompting was needed for operations and engineering personnel to recognize

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that an operability determination should have been completed to evaluate the impact of increased valve weight on the operability of the high pressure core spray system. This indicated a need to further improve the operability determination program and engineering support to operations (Section E1.1).

Bant Support The inspectors determined that licensee management effectively used As Low As

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Reasonably Achievable techniques to minimize radiation dose during the cleaning of the condenser water boxes. Specifically, an additional 5 percent reactor power reduction resulted in about 30 percent dose savings (Section R1.2).

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Report Details Summary of Plant Status The licensee operated the unit at 100-percent power for most of the inspection period. On July 31,1999, the licensee lowered power to 50 percent for condenser water box cleaning.

Power was restored to 100 percent on August 6,1999.

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l. Operations

Conduct of Operations 01.1 Main Control Room Observations

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Inspection Scope (71707)

The inspectors assessed the adequacy of the conduct of operations during multiple

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b.

Observations and Findinas in general, the inspectors observed operations pereonnel responding to plant annunciators in a timely manner and referencing the appropriate annunciator response procedures. Detailed logs were maintained which described shift activities. Operators referenced appropriate Technical Specifications (TS) and entered appropriate Limiting Conditions for Operation (LCOs) when necessary. Control board walkdowns were performed as required by the licensee's conduct of operations procedure. However, the inspectors noted one instance where operators failed to identify a discrepant control board indication.

On August 3,1999, control room ventilation (VC) chiller A unexpectedly tripped.

Operations personnel immediately started VC chiller B. The licensee determined that

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the trip of the VC chiller A trip was determined to be due to a fix-it-now (FIN) team worker placing a jumper in the wrong location while effecting repairs to the VC chiller dehydrator. This caused the control power fuse for the VC chiller A to blow thus causing the chiller to trip.

Later the same day, the inspectors observed the tumover from day shift to swing shift operators and conducted a tantrol board walkdown. During the turnover briefing, operations personnei stated uwt VC chiller A was inoperable due to a blown control power fuse. The inspectors verified that operations personnel had entered TS 3.7.3,

" Control Room Ventilation System," and had taken the TS required actions. However, the inspectors identified that the " Division 1 VC System Out-of-service" switch was not in the "lNOP" [ inoperable] position as required by Procedure 1401.09, " Control of System and Equipment Status." The inspectors questioned the control room supervisor (CRS)

about the out-of-service switch and the status of the annunciator associated with the switch. The CRS reviewed the situation and determined that the control room operators had failed to place the Division i VC switch in the "lNOP" position and the switch was then placed in the required position.

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The inspectors inquired as to why the discrepant switch position had gone unnoticed for nearly a full shift. The CRS indicated that a lack of attention to control panel details was j

the cause of the problem.

Technical Specification 5.4.1.a requires that written procedures be established, implemented, and maintained covering the applicable procedures recommended in Regulatory Guide (RG) 1.33, Revision 2, Appendix A, dated February 1978. Section 1 of Appendix A to RG 1.33, recommended administrative procedures be implemented for

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equipment control. Procedure 1401.09, " Control of System and Equipment Status," is

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an administrative procedure used for equipment control. Section 8.2.1 of Procedure 1401.09 required, in part, that out-of-service (OOS) switches be placed in

"lNOP" position when equipment is inoperable per ITS [lmproved TSs). The inspectors determined that the failure to place the Div-1 VC out-of-service switch in "INOP" when the control-power fuse blew, was a violation of TS 5.4.1.a. However, this Severity Level IV violation is being treated as a Non-Cited Violation, consistent with Appendix C of the NRC Enforcement Policy (NCV 50-461/99014-01). This violation is in the licensee's corrective action program as Condition Report (CR) 1-99-08-22.

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Conclusions The inspectors determined that operations personnel generally responded to plant annunciators in a timely manner, referenced the appropriate annunciator response procedures, made sufficiently detailed log entries, and appropriately referenced TS and LCOs when necessary. However, the inspectors identified a Non-Cited Violation for a discrepant control board indication which had gone unnoticed by control room operators for 7 hours8.101852e-5 days <br />0.00194 hours <br />1.157407e-5 weeks <br />2.6635e-6 months <br />. This illustrated the need for continued improvement in the areas of control board monitoring and shift tumovers.

01.2 Determinina Off-Gas System Release Rates a.

Inspection Scooe (71707)

The inspectors reviewed the circumstances surrounding reports of frequently changing off-gas system release rates since unit startup, b.

Observations and Findinas Since unit startup in May 1999, the reported off-gas system release rate had been fluctuating between approximately 10 microcuries per second and values as high as 200 microcuries per second.

The inspectors questioned engineering personnel and station management as to the cause for the frequently changing reported release rates. Upon investigation, the licensee determined that the cause of the reported changing values was due to operators reading release rate values from the wrong indication channel. The channel being read by operators was a high range channel meant to be used for higher than normal off-gas system release rates. The release rates being read by the operators were actually fluctuations in channel noise and not a fluctuation in the off-gas system release rate. Operations department managers stated that inadequate training on which channel to use during normal power operations was the cause of the problem. Higher

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channels were frequently used during simulator accident scenarios v/th no reference to the proper channel to use during normal operations.

The inspectors noted that no CR was initially written to address the issue. Based on discussions between the inspectors and operations department managers, the inspectors learned that the problem had been discussed internally with operators and that licensee management had concluded that no further action was needed to address the issue. However, after further consideration of the inspectors' concems, operations management generated CR 1-99-09-027. The inspectors noted that the CR had been classified as a "3C" CR, the lowest priority CR, meant for trending only. The CR did not address the " negative training" aspact of the problem (i.e., training for off-gas system readings was only provided for accident scenarios and did not cover normal operating conditions). The inspectors asked if the original CR was properly classified considering the training aspects associated with this issue. Following the exit meeting, licensee management stated that a higher classification level for the CR was appropriate to address the issues raised by the inspectors.-

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Conclusions The inspectors' query prompted the licensee to identify ths, control room operators were referencing the wrong channel for off-gas system release rates. Initially, operations management only addressed the issue intemally with all operators. Later, a CR was written for trending purposes. Based on discussions with the inspectors, the licensee decided that the classification would be raised to a higher level to ensure the extent of condition of this issue was evaluated regarding differences between simulator and main control room instrument settings.

01.3 Online Ma!ntenance LCO Management j

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a.

Insoection Scooe (71707)

The inspectors monitored the licensee's efforts to manage time spent in LCOs to accomplish online maintenance.

b.

Observations and Findinas

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The inspectors assessed the licensee's execution of an unscheduled Division 2 (Div-2)

emergency diesel generator (EDG) outage and scheduled outages to support work on the Division 1 (Div-1) EDG, Div-1 and Div-2 standby gas treatment systems, and Div-2 residual heat removal (RHR) systems. The inspectors verified that appropriate probabilistic risk considerations had been factored into the outage planning and that the correct TS LCOs had been entered. Specific observations included:

Div-2 EDG - Following the identification that fuel oil dilution of the lubricating oil

system had occurred in the Div-2 EDG, the licensee declared the Div-2 EDG inoperable and changed the EDG's lubricating oil. This emergent condition was effectively addressed in 26 hours3.009259e-4 days <br />0.00722 hours <br />4.298942e-5 weeks <br />9.893e-6 months <br /> time (TS prescribe a 72-hour allowed outage time). This issue is discussed more fully in Section M2.1 of this report.

Div-1 EDG - The licensee planned to work on the Div-1 EDG ventilation system

and the planned outage time to accomplish the work activities was approximately i

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48 hours5.555556e-4 days <br />0.0133 hours <br />7.936508e-5 weeks <br />1.8264e-5 months <br />. The allowed outage time prescribed in the TS is 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br />. Initially, work progressed on schedule until severe weather caused suspension of work activities for several hours. While the licensee was electrically connecting the

' diesel ventilation inlet damper hydramotor, a short circuit between two wires caused wiring and distribution panel damage. The wiring was damaged when it was pulled into the hydramotor connection box, The electricians performing the work did not check for grounds on the circuit following repairs; therefore, the condition went unidentified until the circuit was energized. Senior management was invo:ved with developing the repair plans and helped focus maintenance activities in a coordinated manner to ensure that the allrwed outage time would not be exceeded. The repairs were completed and the EDG was declared operable with about 7 hours8.101852e-5 days <br />0.00194 hours <br />1.157407e-5 weeks <br />2.6635e-6 months <br /> of the allowed outage time remaining.

Standby Gas Treatment System (VG) - Work on and testing of the Div-1 and -2

VG systems was completed on schedule without problems.

Div-2 RHR Systems - Planned work activities included Div-2 water-leg pump

maintenance, a water-leg orifice modification, and the cycling of the RHR system train B heat-exchanger isolation valves for data gathering. The inspectors determined that this activity was well controlled and effectively managed.

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Conclusiong The inspectors concluded that the licensee's management of time spent in Limiting Conditions for Operation associated with three maintenance activities was effective.

I However, a poor maintenance practice during an emergency diesel generator outage resulted in an unnecessary delay in completing the outage. As a result, about 90 percent of the allowed outage time was expended for the outage.

O2 Operational Status of Facilities and Equipment O2.1 Enoineered Safety Feature System Walkdown The inspectors reviewed documents related to the standby gas treatment system (VG),

conducted a system walkdown to assess the condition of the system, and observed

- portions of several maintenance activities including charcoal filter replacement and instrument calibrations. All scheduled activities were completed as planned. The inspectors reviewed the maintenancedo status and performance goals for the system and did not have any concems. The inspectors concluded that the standby gas treatment system was appropriately tested and maintained and that system online maintenance was well-managed to ensure it was completed within the scheduled outage time.

O2.2 Review of Out-of-Service (OOS) Annunciator Proaram (71707)

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The inspectors conducted a review of the OOS annunciMor program to determine if the OOS annunciator log was accurate, if monthly and quarterly audits were completed, and if 10 CFR Part 50.5g safety screenings or evaluations were initiated for annunciators that were OOS for greater than 6 months. The inspectors determined that although the total number of OOS annunciators had slowly increased since plant restart, improvements had been made in the inanagement of the OOS annunciator program.

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Specifically, all OOS annuns&s in the MCR were being tracked on the OOS annunciator log, monthly and quarterly audits were completed as required, and there were no OOS annunciators in the MCR greater than 6 months old. Licensee management was also taking action to reduce the number of OOA annunciators.

llhiscellaneous Operations issues 08.1 (Closed) Licensee Event Report (LER) 50-461/96015: Lack of Attention to Detail During Procedure Performance Causes Unplanned Engineered Safety Feature Actuation of Eight Containment Isolation Valves. On October 26,1996, eight containment isolation

' valves closed during the performance of the diesel generator - emergency core cooling system integrated surveillance test. All eight valves were associated with the drywell cooling and chilled water system. The plant was in a shutdown condition throughout the event. The licensee determined that the valves closed due to a lack of attention-to-detail by operations personnel. Operations personnel reviewed the surveillance test procedure and prerequisites before commencing testing to ensure that an unplanned equipment actuation did not occur and mistakenly determined that certain prerequisites did not need to be accomplished prior to conducting the surveillance test. This resulted in removing the prerequisites from the test procedure that would have prevented the isolation valves from closing. As part of the corrective actions for this event, the licensee conducted training and discussed management's expectations for reviewing procedures and prerequisites. Training on procedure use and adherence was also held i

to emphasize management's expectations.

08.2 (Closed) LER 50-461/97003: Disconnecting Division I intermediate Range Nuclear Monitor Caused a Reactor Scram. On January 27,1997, with the reactor in cold

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shutdown, a reactor scram signal was generated when one intermediate range nuclear j

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monitor in Division I and one monitor in Division ll were simultaneously de-energized.

On January 26,1997, operations personnelissued a safety tagout to replace a cable

connector on the Division I channel F intermediate range nuclear monitor. The following day, maintenance personnel identified that work was also required to be completed on the Division ll channel E monitor. Operations personnel determined that to work on both channels simultaneously the intermediate range nuclear monitor sensor switches for the respective channels needed to be placed in bypass so that a scram signal would not be

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gaerated during the work. However, information regarding the need to use the sensor bypass switch was not clearly communicated to the next operations crew. Work i

commenced on the next shift and when both channels were de-energized simultaneously without bypassing the sensors, an automatic scram signal was generated.

i The licensee determined that this event occurred due to personnel error. The

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operations shift supervisor counseled the individuals involved in the event. Each of the counseling sessions stressed the importance of providing adequate turnovers and questioning the effect of new work on existing work activities. Operations management q

also implemented a peer checking program and an enhanced turnover process to improve operator performance and communications. The inspectors completed several observations of control room activities and observed improved communications between operations personnel. In addition, issues involving safety tagging were the subject of NRC Manual Chapter 0350 Case Specific Checklist item 11.2, " Establish and Implement

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an Effective Equipment Clearance Program.' This item was closed in NRC Inspection Report 50-461/98017.

08.3 (Closed) LER 50-461/98002: Loss of Service Air Results in Unplanned Engineered Safety Feature Actuation and Manual Reactor Scram. On January 23,1998, with the reactor in cold shutdown, the operating air compressor tripped on high oil temperature, resulting in the ;oss of service and instrument air. A backup air compressor had previously tripped, also on high oil temperature, and was unavailable. Operators recognized that air pressure was decreasing and inserted a manual scram signal per off-normal operating procedures. The details of this event were discussed in NRC Inspection Report 50-461/98006. The licensee determined that the root cause of the event was that it was not easy for the operators to adjust the controller for the cooling water flow to the oil coolers which resulted in an Imbalance of cooling to the oil coolers and high oil temperatures.

Engineering personnel developed design changes for the service air and component cooling water systems to improve the operators' ability to control service air compressor oil temperature. The inspectors discussed the design changes with engineering personnel and did not have any concems. The licensee installed the improved designs for one of the service air compressors before startup. No new issues ware identified in the LER.

08.4 (Closed) LER 50-461/98020: Inadequate Flow Balancing of Shutdown Service Water System Resulted in Less Than Required Flow to the System Loads. This issue involved the inspectors' observation that excess system flow was bypassing the Division I residual heat removal system heat exchanger. This observation was documented in NRC Inspection Report 50-461/98011 and a violation for which enforcement discretion was exercised was issued.

The licensee determined by using analytical models, that the high flow through the residual heat removal system heat exchanger bypass line reduced shutdown service water system flow to other loads. The reduced flow to the emergency core cooling system room coolers lowered the heat removal capability and resulted in the licensee

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needing additional time to develop secondary containment negative pressure during an accident. This could result in offsite doses greater than those described in the Updated Safety Analysis Report but less than the limits prescribed in 10 CFR Part 100. The licensee implemented corrective actions to test the shutdown service water flow distribution. Based on the results of the flow balance test, the licensee installed, where needed, flow restricting elements in the bypass lines and made necessary repairs or adjustments to system components.

08.5 (Closed) LER 50-461/98033: Inappropriate Clearing of a Caution Tagout Results in Improved TS LCO 3.4.10 Action A.1 Not Being Met. On October 7,1998, with the reactor in cold shutdown, the licensee determined that the Division ll shutdown cooling and shutdown service water systems were inoperable and that TS 3.4.10, Action A.1 was not met. The licensee determined that the inoperability condition resulted from inappropriate clearing of caution tags.

The licensee had previously determined that to maintain the required shutdown service water system flow balard:e to safety-related components, the residual heat removal system heat exchanger must be lined-up with no bypass flow. This line-up was

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necessary until the licensee installed appropriate flow restricting elements. To ensure i

that the temporary line-up was implemented, the licensee issued cautions tags. The caution tags provided instructions to keep the heat exchanger's service water inlet and outlet valves fully open and the bypass valve closed.

On October 6,1998, the flow orifice for the Division I shutdown service water system was installed. Operations personnel then removed all of the caution tags. The next day, operations personnel placed the residual heat removal system train A into the shutdown cooling mode of operation and removed the residual heat removal system train B from operation. This caused the service water system inlet and outlet valves to the train B heat exchanger to close and returned the bypass valve to the automatic function. About 3.5 hours5.787037e-5 days <br />0.00139 hours <br />8.267196e-6 weeks <br />1.9025e-6 months <br /> later, operations personnel recognized that the Division ll shutdown service water system was inoperable due to the valve repositioning. The licensee also realized that the residual heat removal system train B shutdown cooling system was inoperable. Technical Specification 3.4.10, Action A.1, required operations personnel to verify that an attemate method of decay heat removal was available for each inoperable residual heat removal shutdown cooling subsystem within 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br />.

However, actions required to comply with TS 3.4.10, Action A.1, were delayed due to operations personnel not recognizing that the service water system was inoperable.

Once operators recognized that the service water system was inoperable, actions to meet TS 3.4.10, Action A.1, were promptly taken. The failure to verify that an alternate method of decay heat removal was available within 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> as required by TS 3.4.10 was determined to be a TS violation. This Severity Level IV violation is being treated as a Non-Cited Violation (NCV 50-461/98012-01), consistent with Appendix C of the NRC Enforcement Policy. This violation is in the licensee's corrective action program as LER 50-461/98-033.

The licensee revised Proceoure 1014.06, " Operability Determination," to ensure that operability of multi-divisional systems was considered before removing tags. Licensee management counseled the shift management that released the caution tagout. The licensee also provided lessons learned training to the operations and design engineeiing departments. The inspectors considered the licensee's corrective actions adequate.

08.6 (Closed) LER 50-461/98036: Opening incorrect Electrical Cubicle Caused Loss of Shutdown Cooling and Leads to Failure to Meet TS Required Action in the Required Time. On October 18,1998, operations personnel were clearing a tagout when they opened the wrong potential transformer fuse cubicle door (see Inspection Report 50-461/98018 for details). As the door was opened, a safety device caused a trip of the Division I bus and the loss of shutdown cooling. The plant was in an extended shutdom houghout the event.

Technical Specification 3.4.10, " Residual Heat Removal Shutdown Cooling System,"

Action 8.1, requires that reactor coolant circulation be established within 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> of the loss of shutdown cooling. However, due to plant conditions, reactor coolant circulation was not restored fe-3 hours and 14 minutes. The failure to restore reactor coolant circulation within the time required by TS 3.410 was determined to be a TS Wolation.

This Severity Level IV violation is being treated as a Non-Cited Violation (NCV 50-461/98012-02), consistent with Appendix C of the NRC Enforcement Policy.

This violation is in the licensee's corrective action program as LER 50-461/98-036.

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The licensee initiated several corrective actions. Operations personnel received training regarding the location of specific potential transformer fuse cubicles. The safety tagging p

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program was revised to provide additional guidance. Procedure 3312.03, " Residual Heat Removal, was revised to allow placing a residual heat removal system loop that was previously aligned to the suppression pool into the shutdown cooling mode of operation. The procedure was also revised to ensure the licensee could comply with TS 3.4.10, Required Action B.1. The inspectors considered the licensee's corrective actions adequate for this issue.

II, Maintenance M1 Conc:ct of Maintenance M1.1 General Comments (61726. 62707)

The inspectors reviewed or observed portions of the following maintenance and surveillance activities.

Procedure 3310.01, " Reactor Core _ lsolation Cooing [RCIC)"

Procedure 8209.50, " Welding Procedure for Bi-Process Welding of Carbon Steel" Procedure 8801.01, " Instrument Calibration" Procedure 8801.02, " Loop Calibration" Procedure 9054.01C001, "RCIC Cold Quick Start Check" Procedure 9866.01, "VGNC HEPA Filter Leak Test" Procedure 9866.02, "VGNC Charcoal Adsorber Leak Test" AR F07186, " Troubleshoot thermal-purge solenoid (OFSV-VC614A)"

AR F07614, "Div 1 Average Power Range Monitor Back Panel Connector Loose" AR F07616, "Drywell Floor Drain Leakage Erratic" AR F05090, " Intermediate Range Monitor "A" Readings Fluctuating" AR F06244, " inadequate Stroke Length (1VD01YA Damper)"

AR F08197, " Rework 1VD01YA Damper Blades" AR F09529, " Modify Division 2 Water Leg Orifice Assembly" The inspectors determined that workers closely followed procedures while conducting these work activities. No substantive findings were identified during the inspectors'

observations.

M2 Maintenance and Material Condition of Facilities and Equipment M2.1 Division 2 Emeroency Diesel Generator inoperability a.

Inspection Scope (62707)

The inspectors reviewed the circumstances surrounding the licensee's identification that the Div-2 EDG lubricating oil had been diluted by the EDG fuel.

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Observations and Findinas On August 9,1999, the licensee declared the Div-2 EDG inoperable after receiving a confirmatory oil analysis which indicated that there was excessive fuel dilution in the lubricating oil for the 16-cylinder engine. The licensee developed a plan to identify and eliminate the source of the fuel dilution. The licensee identified a leak of fuel from the No.12 cylinder fuel-injector to fuel-retum line connection. The leak rate was calculated to be about 1/3 of a gallon per hour. The licensee repaired the fuel leak, performed a satisfactory post-maintenance test, and declared the Div-2 EDG operable on August 10, 1999.

The inspectors reviewed the licensee's actions and evaluations to ensure that no other diesel engine had a fuel dilution problem and determined that they were acceptable. On August 10, the licensee informed the NRC that this event was a 1-hour non-emergency reportable event under 10 CFR 50.72(b)(1)(ii)(B), "as a condition outside the design basis of the plant because of the discovery that the Division 2 diesel generator had been incapable of performing its design function (intended safety function) for an extended period of time during [ plant] operation."

The licensee entered the event into its corrective action system (CR 1-99-08-055) on August 8 and elevated it to the highest level of review and root-cause determination on August 12,1999. The licensee's root cause determination and corrective action development were stillin progress at the end of the inspection period. Pending the NRC's evaluation of the licensee's root-cause determination and corrective actions, the Div-2 EDG inoperability issue will be treated as an unresolved item (URl 50-441/99014-02).

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Conc!usions The licensee determined that the Division 2 emergency diesel generator had been inoperable for an extended period of time during plant operation. The inspectors identified an unresolved item for this condition.

M3 Maintenance Procedures and Documentation M3.1 Maintenance Procedure Deficiencies Contribute to Plant Transients and Eauipment Problems a.

Insoection Scope (62707)

The inspectors evaluated the causes of several recent plant transients and equipment problems to determine if potential common causes existed.

b.

Observations and Findings in NRC Inspection Report 50-461/99010, the inspectors documented that several maintenance procedure deficiencies led to plant transients and equipment problems.

The deficiencies ranged from source range monitor set point errors during reactor startup activities to inadequate guidance for feedwater control valve maintenance which led to a reactor scram. In Section 01.1 of Inspection Report 50-461/99013, an event was described where the No.1 turbine bypass valve opened unexpectedly. The

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licensee determined that this event was caused by inadequate procedures that were used to calibrate the steam pressure regulating system and adjust the turbine bypass valve bias. In Section M2.1 of this report, a condition where the Division 2 EDG was rendered inoperable due to fuel oil dilution of the lubricating oil is described. In this case, it appears that a maintenance procedure which did not require post-maintenance testing for the EDG fuel system contributed to the problem. The licensee had not completed the root cause investigation for this event at the end of the inspection period.

In each of these examples, inadequate maintenance procedures led to unnecessary challenges to plant operators. The inspectors noted that specific corrective actions had been taken to address the individual problems. The inspectors questioned licensee management to determine if an evaluation had been initiated to determine the extent of condition of procedural deficiencies. Licensee management stated that no broad scope review was currently underway; however, a broad scope plan for a maintenance procedure review was scheduled to be completed by the end of 1999.

c.

Conclusions The inspectors and the licensee have identified multiple examples of deficiencies with maintenance procedures over the last 3 months. The procedure deficiencies have caused equipment problems and plant transients that have unnecessarily challenged operations personnel. A broad scope review of maintenance procedures had not been initiated and was not planned to be completed until the end of 1999.

M3.2 Fix-It-Now (FIN) Team Safetv-Tzooina Procedure inadeauacies (62707)

a.

Inspection Scope (62707)

The inspectors reviewed the licensee's evaluation if its FIN Team safety tagging and control program.

b.

Observations and Findinas During a review of the FIN team safety tagging (tagout) and control program, the licensee identified several inadequacies with existing maintenance procedures. The more significant inadequacies were:

None of the licensee's tagout procedures adequately addressed the use of a

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FIN team tagout by non-FIN team members.

Clearly defined responsibilities and tigout clearance requirements were not

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presented.

Requirements for equipment manipulation by non-FIN team members for

equipment controlled by a FIN tagout were not contained in procedures.

Requirements for supervision of non-FIN team personnel working independently

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under FIN procedures were not contained in procedures.

Technical Specification 5.4.1.a requires that written procedures be established, implemented, and maintained covering the applicable procedures recommended in

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Regulatory Guide (RG) 1.33, Revision 2, dated February 1978. Section 1 of Appendix A to RG 1.33, recommended that administrative procedures be implemented for equipment control. Clinton Power Station Procedure 1014.01, " Safety Tagging,"

Revision 27, which is an administrative procedure used for equipment control, was inadequate in that clear instructions were not provided for FIN team safety tagouts. This is considered a violation of T.S. 5.4.1.a. However, this Severity Level IV violation is being treated as a Non-Cited Violation, consistent with Appendix C of the Enforcement Policy (NCV 50-461/99014-03). This violation is in the licensee's corrective action program as CR 1-99-07-039.

The licensee planned to revise the FIN team safety tagging procedure to describe the use of the FIN team safety tagging process by other maintenance groups, to define who can be a tagout holder, and to provide directions regarding the tumover of FIN team work to other groups. The licensee stated that it plans to brief all maintenance

- personnel prior to the issuance of the procedure revision.

c.

Conclusions One Non-Cited Violation was identified regarding inadequate procedures which were used for equipment control during FIN team activities.

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M4 Maintenance Staff Knowledge and Performance M4.1 Residual Heat Removal System W31erlea Pumo Orifice Modification Weldina a.

Inspection Scope (62707)

The inspectors reviewed personnel welding qualifications, welding processes, and the materials used to install modified flow orifices in the Div-2 RHR water-leg pump discharge piping. The inspectors also observed work at the job site.

b.

Observations and Findinas On August 25,1999, the inspectors observed that welders had attached the ground lead for their welding macNne directly to a ground strap between the station ground and the conduit containing the wiring to the welder supply outlet rather than to the piece of material being welded (work piece) at the job site. When questioned, both the welder at the job site and the immediate supervisor stated that attaching the ground lead to the nearest station ground was the normal practice.

The inspectors reviewed the applicable national electrical codes, welding codes, the welding machine technical manual, and American National Standards Institute (ANSI)

Standard Z49.1, " Safety in Welding and Cutting," and noted that all of these references recommended that the ground lead be attached to the piece of material being welded as close as possible to the actual weld area. Specifically, not attaching the welding lead directly to the work piece increases the current pathways back to the welding machine which could cause plant instrument inaccuracies due to electro-magnetic field (EMF)

radiation and stray currents, personnel safety hazards due to electrical shock pathways, plant equipment damage, effects on weld quality for large-diameter pipe weld processes, and melted wiring insulation from heated conduits and overheated lifting cables. The inspectors aise observed that the welding lead was a larger wire size than

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the grounding cable attached to the station ground which could cause the current rating

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of the grounding cable to be exceeded. The inspectors discussed the concems about this practice with the mechanical maintenance supervisor. The supervisor had CR 1-99-08-150 written to prompt an investigation of the inspectors' concems and

~ directed that all welding ground leads be connected as close as practical to the work piece.

c.

Conclusions The inspectors identified a poor practice of connecting welding machines to the station ground which could create significant hazards to both personnel and equipment.

M8 Miscellaneous Maintenance issues M8.1 (Closed) LER 50461/96019: Misst,a Surveillance Testing of Source Range Nuclear Monitors' Reactor Period Display. The licensee identified that the reactor period display was not tested since initial plant operations. The licensee determined that a i

misinterpretation of TS bases resulted in deleting the verification of the reactor period display in plant procedures. The licensee revised the source range nuclear monitors'

surveillance procedures to ensure that the reactor period display was tested as required.

The inspectors reviewed the revised procedures and verified that the reactor period display was tested appropriately. In addition, as part of the licensee's Plan for Excellence, the licensee completed a system surveillance test review to identify other inadequate surveillance tests. The NRC reviewed the system surveillance test review results as part of the closure activities for NRC Manual Chapter 0350 Case Specific Checklist item VI.1, " Provide Reasonable Assurance that Safety-Related Structures, Systems, and Components Will Perform Their Intended Safety Functions as Described in the Design and Licensing Basis." The inspector's conclusions are documented in Inspection Report 50461/1999003. The inspectors considered the licensee's actions adequate.

M8.2 (Closed) LER 50461/96020: Leaking instrument Air Line Fitting Resulted in a Reactor Scram. On December 23,1996, with the reactor in cold shutdown, a leaking instrument air line fitting catastrophically failed while mechanical maintenance personnel were fixing leaks in the system. As a result of the failure, the instrument air system header bled i

down, the scram discharge volume inlet and outlet valves repositioned, and a reactor scram signal was received due to high scram discharge volume water level. The licensee determined that the instrument air line failure was caused by repetitive over tightening of an instrument air line fitting. This resulted in thinning and then shearing of

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the air line when a small force was applied. The over tightening was the result of the licensee's practice of allowing operations personnel to tighten leaking fittings as necessary. The licensee eliminatet' this practice and maintenance personnelinspected the integrity of all instrument air lines and fittings connected to the control rod drive system. Several sections of instrument air lines and the associated fittings were subsequently replaced. The inspectors reviewed the licensee's corrective actions and determined that the actions were adequate.

M8.3 (Closed) LER 50461/97011: Circuit Breaker Omitted From Surveillance Procedure Resulted in Not Meeting TS 3.8.9. The licensee identified that TS 3.8.9, " Distribution System - Operating," and 3.8.10, " Distribution System - Shutdown." were not met. The licensee discovered that circuit breaker CB-8 was omitted from the surveillance test

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procedures used to verify compliance with TS Surveillance Requirements 3.8.9.1 and 3.8.10.1. Circuit breaker CB-8 connected the Division ill battery bus to the Division 111 125-volt direct current distribution bus. Technical Specifications required operations personnel to verify the position of certain circuit breakers, including circuit breaker CB-8,

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every 7 days. The failure to satisfy the requirements of TSs 3.8.9 and 3.8.10 was considered a violation. This Severity Level IV violation is being treated as a Non-Cited Violation (NCV 50-461/98012-03(DRP)), consistent with Appendix C of the NRC

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Enforcement Policy. This violation is in the licensee's corrective action program as i

LER 50-461/97011.

The licensee determined that only circuit breaker CB-8 was omitted from the surveillance procedures. Because the Division ill 125-volt direct current distribution bus is different from the other divisions with a circuit breaker between the battery bus and the direct current distribution bus, the licensee determined that the circuit breaker was overlooked when the surveillance procedures were developed.

Operations personnel immediately verified that circuit breaker CB-8 was closed and revised the respective surveillance procedures. Drawings were also reviewed to ensure that all required breakers were included in the surveillance procedures. No deficiencies were identified. The inspectors reviewed the licensee's corrective actions and considered them adequate.

l M8.4 (Closed) LER 50-461/97014: Main Steam Isolation Valves (MSIV) Closure Times Outside of Technical Specifications Due to Procedural Inadequacy. Technical Specification Surveillance Requirement 3.3.6.1.6 required the isolation time for each MSIV to be between 3 and 5 seconds. Technical Specification Surveillance Requirement 3.3.6.1.7 required verification that the main steam isolation response time for the MSIVs was within limits. The licensee identified that surveillance test Procedure 9061.09, " Main Steam /Feedwater System Valve Operability," did not adequately measure the full MSIV closure time due to its failure to fully account for instrument inaccuracies. The licensee applied the uncertainties associated with instrument inaccuracies to historical test results and identified that on various occasions, four of the eight MSIVs did not meet TS required closure times. The first instance where recorded time measurements did not meet TS requirements was on April 26, 1988. The most recent instance was on May 20,1997, about the time the procedural inadequacy was discovered.

The requirements of 10 CFR Part 50, Appendix B, Criterion V, " Instructions, Procedures, and Drawings," state, in part, that activities affecting quality shall be prescribed by i

documented instructions, procedures, and drawings of a type appropriate for the circumstances. Test Procedure 9061.09, " Main Steam /Feedwate r System Valve Operability," which prescribes activities affecting quality, was inappropriate for the circumstances which is a violation of Criterion V. This Severity Lovel IV violation is being treated as a Non-Cited Violation (NCV 50-461/98012-04(DRP)), consistent with Appendix C of the NRC Enforcement Policy. This violation is in the licensee's corrective action program as LER 50-461/97014. In response to this isste, licensee personnel l

initiated CR 1-97-05-237 and revised Procedure 9061.09 to include the appropriate testing methodology. The affected MSIVs were subsequently re-tested using the revised procedure and satisfactory closure times were achieved.

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M8.5 (Closed) LER 50-461/97036: Failure of Cooling Unit Manufacturer to Install Motor Shaft Key Leads to Inoperability of Shutdown Service Water Pump Room Cooling Unit. On December 19,1997, while the reactor was in cold shutdown, the licensee identified that

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the motor shaft key for the Division ll shutdown service water pump room cooling fan i

was missing. The motor shaft key connected the cooling fan's motor shaft to the fan J

hub.

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The licensee determined that maintenance involving the removal of the motor shaft key had never been initiated. Therefore, the licensee concluded that the vendor had not incerted the motor shaft key into the keyway during manufacturing. Corrective actions for this event included installing a new motor shaft key in the keyway and inspecting several other room coolers manufactured by the same vendor. No other missing keys i

were identified. The licensee issued a 10 CFR Part 21 Report (No. 21-98-002). The inspectors observed a portion of the licensee's inspections and considered the licensee's actions adequate.

M8.6 (Closed) LER 50-461/98018: Engineered Safety Feature Actuation Caused by Deficiencies in the Method Used to Perform Nuclear System Protection System Power Supply Adjustment. On April 16,1998, while the reactor was in cold shutdown, an engineered safety feature actuation occurred. The licensee determined that the actuation was caused by inadequate maintenance practices. After replacing the Division ll nuclear system protection system power supply A, a maintenance technician over-adjusted the potentiometer. This resulted in a rapid voltage increase and a trip of the power supply on over voltage resulting in a loss of nuclear system protection system logic.

The licensee determined that the technician encountered excessive resistance while adjusting the potentiometer. The technician was using a small non-rigid plastic screwdriver. As the force from the plastic screwdriver was applied to the potentiometer, j

the plastic screwdriver flexed and the potentiometer moved more than expected.

Operations personnel entered Off-normal Procedure 4001.02C002, " Automatic isolation Checklist," and directa ' Me mair% nance technician to stop work. After approximately 3 minutes, the DivisioA i nuclear system protection system bus was re-energized. Once these actions were complete, operations personnel completed system and component restorations without further difficulties.

The licensee determined that this event was preventable since the event was caused by deficiencies in the method used to complete the power supply adjustments. Immediate corrective actions included incorporating the lessons teamed from this event into the maintenance work packages written to replace and adjust nuclear system protection system power supplies in the remaining three electrical divisions. The licensee also developed a maintenance procedure to provide guidance on the replacement and adjustment of nuclear system protection system power supplies. The inspectors discussed the corrective actions with maintenance supervision and had no additional concems. The inspectors considered the licensee's corrective actions adequate.

MB.7 (Closed) LER 50-461/98035: Failure to Comply with TS Action Requirements to immediately Restore Alternating Current (AC) and Direct Current (DC) Electrical Power Sources Due to inadequate Communications, Questioning Attitude and independent Oversight. On October 16,1998, while the reactor was in cold shutdown, operations

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personnel removed the Division il essential switchgear heat removal system from n

service for scheduled maintenance. Since the essential switchgear heat removal system removes heat generated by equipment in the engineered safety feature switchgear room, cable spreading room, battery room, and inverter room, operations personnel were required to declare the Division ll electrical distribution systems inoperable. Technical Specification 3.8.2, " Electrical power systems - attemating current

sources during shutdown conditions," and 3.8.5, " Electrical power systems - direct I

current sources during shutdown conditions," require immediate actions to restore the

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electrical distribution systems to an operable status.

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Technical Specification Section 1.3, " Completion Times," defines immediate actions as

" actions that should be pursued without delay and in a controlled manner." On October 17, the shift manager questioned work management personnel about the

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completion of maintenance on the essential switchgear heat removal system. The shift manager was informed that work had not started due to resource restraints. The shift manager recognized that the failure to immediately begin work on the essential switchgear heat removal system violated TSs 3.8.2 and 3.8.5 and directed ope:ations personnel to take actions to restore the essential switchgear heat removal s.1 stems to operable status as soon as possible. The failure to take immediate actions to restore the, electrical distribution buses is a violation of TSs. This Sevedty Level IV violation is being treated as a Non-Cited Violation (NCV 50-461/98012-05(U @)), consistent with Appendix C of the NRC Enforcement Policy. This violation is in tiie licensee's corrective action program as LER 50-461/98035.

The licensee determined that a lack of communications, questioning. pitude, and independent oversight contributed to this event. Control room operatio.a management failed to communicate to the work coordinator and work management that renioval of the essential switchgear heat removal system from service required entry into two immediate TS action statements. In addition, work management personnel failed to inform operations personnel when delays were encountered in completing the essential switchgear heat removal system maintenance.

In response to this event, the licensee revised the LCO tracking database to include TS action completion times. Operations and work management personnel attended a briefing that addressed the need for personnel to question known TS requirements and to forward information which may impact TS requirements to the appropriate personnel.

The licensee also enhanced the independent oversight of TS action completion times by including the completion times as part of the information provided to management

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personnel during the daily plant status meeting. The inspectors reviewed the LCO

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tracking database and the information provided in the daily plant status meeting to ensure that TS action completion times were being properly communicated throughout the site. No concerns were identified. The inspectors considered the licensee's corrective actions adequate.

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111. Engineerina E1 Conduct of Engineering

' E1.1 Hiah Pressure Core Sorav (HPCS) System Valve Weiaht inconsistencies a.

Insoection Scope (37551. 71707)

The inspectors reviewed the licensee's analysis of inconsistencies in vendor information regarding the total valve weight of two HPCS system valves.

b.

Observations and Findinos -

On July 30,1999, engineering personnel discovered inconsistencies in vendor information regarding the total valve weight of two HPCS system valves. Anchor Darling Valve Drawing 2999-3, Revision J, stated that the total valve weight of each valve was 3260 pounds. Anchor Darling Design Calculation R83.064 listed the valve weight as 3754 pounds. Due to the large difference in valve weight, and the potential impact on the seismic qualification for the HPCS system, engineering personnel initiated CR 1-99-07-165 to document this issue. Within the problem description section of the CR, engineering personnel stated that the increased valve weight would degrade two HPCS pipe supports but would not affect the ability of the HPCS system piping to perform its safety function under a worse case loading scenario. The inspectors determined that the engineer's statement meant that the licensee considered the HPCS system piping to be degraded but operable; however, an operability determination had not been conducted to evaluate this issue.

The inspectors immediately questioned operations personnel on the need for an OD for CR 1-99-07-165. After an initial review, the operations support supervisor determined that an OD was needed to evaluate the impact of the increased weight on HPCS system operability and informed the shift manager. An OD was completed several hours later.-

Operations department management determined that the shift manager had not immediately recognized the need for an OD since engineering personnel had completed an engineering evaluation of the issue. During a subsequent review of the engineering evaluation, the inspec'xs identified that engineering personnel had known an OD was needed but proceec.ed with completing the engineering evaluation without alerting operations personnel of the need for an OD. Speciiically, engineering personnel concluded the engineering evaluation with the statement " functional capability of the HPCS system was assured per Generic Letter 91-18, Revision 1."

On August 26, the inspectors reviewed OD 1-99-07-165, Revisions 0 and 1, for technical adequacy. The inspectors determined that the licensee used the methodology provided in Section 6.13, " Piping and Pipe Support Requirements," of NRC Inspection Manual Part 9900," Operable / Operability: Ensuring the Functional Capability of a System or Component," to demonstrate continued operability of the HPCS system pipe supports. No deficiencies were identified.

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Conclusions Inspector prompting was needed for operations and engineering personnel to recognize that an operability determination should have been completed to evaluate the impact of increased valve weight on the operability of the high pressure core spray system. This indicated a need to further improve the operability determination program and

engineering support to operations.

E8 Miscellaneous Engineering issues E8.1 (Closed) Notice of Violation 50-461/96412-29: Inadeque testing of feedwater check valves. In October 1996, the inspectors and the licensee determined that testing of the feedwater check valves, as required by 10 CFR Part 50, Appendix J, was inadequate in that water was not drained below the seating surfaces of the outboard feedwater primary containment isolation valves prior to conducting leak rate testing. As a result, these containment isolation valves were inoperable during operating cycle six (April 1995 - September 1996). The licensee attributed the cause of this violation to poor original plant design and a lack of familiarity of system design by leak rate testing personnel. The licensee determined that the segment of feedwater piping between the inboard and outboard feedwater primary containment isolation valves was sloped at a 0.5 degree angle toward the outboard isolation valve. As a result, the drain lineup used to prepare the feedwater system for testing trapped water in the outboard isolation valve such that an adequate leak rate air test could not be completed.

As part of the corrective actions for this issue, the licensee installed drain valves on the bottom of both outboard feedwater primary containment isolation valves to allow for complete draining prior to conducting leak rate testing. The leak rate testing procedure was also revised to instruct that the area around the outboard feedwater primary containment isolation valves be drained prior to testing. Lastly, the licensee reviewed all other containment penetrations that were subject to type C air leak testing to ensure that a similar draining issue was not present. No discrepancies were identified. The inspectors observed the installation of the drain valves, reviewed the revised procedure, arsd verified that no similar draining issues were identified during the licensee's review.

The inspectors considered the licensee's corrective actions adequate.

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i E8.2 (Closed) Notice of Violation 50-461/96412-30: Inadequate corrective actions for feedwater check valves. In October 1996, the inspectors determined that the licensee had not implemented effective corrective actions to preclude repeated failures of the outboard feedwater primary containment isolation valves to pass the as-found leak rate air test conducted during each refueling outage. In response to this issue, the licensee modified the actuators on the outboard feedwater primary containment isolation valves to provide an increased closing force on the valve and to ensure that the closing force was adequately translated across the entire valve disk.

Tu ispectors observed the as-left testing for these valves and verified that the test results were satisfactory. However, a subsequent as-found test had not yet been required to be completed. As part of the resolution of this issue. the licensee has committed to completing an as-found test as part of a mid-cyde outage currently scheduled for April 2000. In addition, the licensee has submitted a TS amendment (LS-97-006) to the NRC on October 23,1998. The purpose of the amendment is to gain approval to implement a feedwater leakage control system mode of the residual heat

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removal system. If approved by the NRC, the periodic leakage testing requirement for the outboard feedwater primary containment isolation valves would change such that a water test could be conducted rather than an air test. If the amendment is not i

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approved, the licensee will be required to continue conducting air tests in accordance with 10 CFR Part 50, Appendix J. The inspectors considered the licensee's corrective actions a be adequate.

E8.3 (Closed) LER 50-461/96014: Inadequately Tested Auxiliary Building Roof Plug Leads to j

Secondary Containment inoperability When Secondary Containment was Required to be Operable. During several refueling outages, the licensee has installed an altemate j

auxiliary building roof plug to allow easier movement of material in and out of the main steam tunnel and secondary containment. Before the beginning of the sixth refueling

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outage, engineering personnel concluded that testing of the tightness of the secondary containment was required to ensure that containment integrity was maintained. The test was to be done before declaring the attemate auxiliary building roof plug and secondary containment operable.

During a later review, engineering personnel determined that a secondary containment integrity test was not completed following the installation of the attemate auxiliary

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building roof plug on March 20,1995 (fifth refueling outage). The failure to complete an Integrity test resulted in the secondary containment being inoperable during core alterations completed on March 22,1995, and in a violation of TS 3.6.4.1 which requires that actions be taken to immediately suspend core alterations if secondary containment becomes inoperable during fuel movement. This Severity Level IV violation is being treated as a Non-Cited Violation (NCV 50-461/98012-06(DRP)), consistent with Appendix C of the NRC Enforcement Policy. This violation is in the licensee's corrective action program as LER 50-461/96014.

The licensee attributed the cause of this event to an inadequate design change procedure in that the procedure did not contain adequate information to determine the testing required when installing a design change. Poor attention to detail also contributed to this event. Specifically, the design change initiator labeled the alternate roof plug design change request as a change to a security barrier without recognizing the impact on secondary containment operability.

As par: of the licensee's corrective actions for this issue, Procedure 1003.01, " CPS Hardware Change Program," was revised to ensure that it contained sufficient detail for determining design change testing. The design change for the attemate auxiliary building roof plug was also revised to specify that a secondary containment integrity test needed to be completed before declaring the rod plug and secondary containment operable. The licensee conducted training to reinforce the actions to be taken when determining design change testing. The inspectors considered the licensee's corrective actions adequate.

E8.4 (Closed) LER 50-461/97004: Inadequate Procedure Leads to Failure to implement TS Surveillance Requirement 3.6.5.3.3. On February 4,1997, engineering personnel determined that residual heat removal system heat exchanger shell vent valves 1E12-F073A and -B had not been verified closed as required by TS 3.6.5.3.3.

The licensee determined that this condition existed since initial plant startup.

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The licensee was unable to determine the root cause of this event due to the age of the issue. However, the most likely cause was that the valves were omitted in surveillance test Procedure 9060.01, "Drywell Integrity Verification," due to a lack of knowledge by the procedure preparer. In response to this issue, the licensee verified that the affected valves were closed. The licensee also revised the surveillance procedure to ensure that the valves continued to be verified closed as required by TS. In addition, a listing of all other manual drywell isolation valves was reviewed to verify that the valves were included in the respective surveillance procedures. Using an inadequate surveillance test procedure is a violation of Criterion V, " Instructions, Procedures, and Drawings," to Appendix B, " Quality Assurance for Nuclear Power Plants and Fuel Reprocessing Plants," to 10 CFR Part 50. This Severity Level IV violation is being treated as a Non-Cited Violation (NCV 50461/98012-07(DRP)), consistent wit' Appendix C of the NRC Enforcement Policy. This violation is in the licensee's corrective action program as LER 50-461/97004.

During the review of this issue, the licensee also determined that the valves were not being adequately tested as part of another surveillance test. The requirements of surveillance test 9861.07, "Drywell Bypass Leak Rate Test," were not met due to the ends of the vent valve's piping being partially submerged during the test. The licensee evaluated previous surveillance test data using the assumption that the valves failed open and were not submerged. The licensee concluded that the integrity of the secondary containment was not affected. Long term corrective actions included reviewing other drywell penetrations to identify other piping which may be partially submerged during testing, making the appropriate changes to the surveillance I

procedures as necessary, and reviewing all remaining surveillance tests as part of the system surveillance test review initiative. The inspectors reviewed the licensee's initial and long-term corrective actions and considered them adequate.

E8.5 (Closed) LER 50-461/97009: A Surveillance Test Procedure Did Not Adequately Consider the Accuracy of Installed Instrumentation in Meeting TS Requirements for the Reactor Core Isolation Cooling (RCIC) System Pump. This issue involved the licensee's identification that instrument inaccuracies had not been applied to the acceptance criteria used to demonstrate compliance with several TS surveillance requirements. For example, TS Surveillance Requirement 3.5.3.3, required the licensee to verify that the RCIC pump operated at a flow rate greater than or equal to 600 gpm at required pressures. However, on March 26,1997, licensee personnel identified that they were unable to confirm that previous RCIC system surveillance tests met TS Surveillance Requirement 3.5.3.3 when instrument inaccuracies were applied. The failure to satisfy this requirement resulted in the licensee not meeting the requirements of TS 3.5.3,

"RCIC System," while operating in Mode 1,2, or 3. Criterion V, " Instructions, Procedures, and Drawings," to Appendix B, " Quality Assurance for Nuclear Power Plants and Fuel Reprocessing Plants," to 10 CFR Part 50, states, in part, that activities affecting quality shall be prescribed by documented instructions, procedures, or drawings, of a type appropriate to the circumstances. The failure to adequately prescribe documented instructions to verify the RCIC system pump operated at a flow rate greater than or equal to 600 gpm at required pressures, an activity affecting quality, is a violation of Criterion V. This Severity Level IV violation is being treated as a

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Non-Cited Violation (NCV 50-461/98012-08(DRP)), consistent with Appendix C of the NRC Enforcement Policy. This violation is in the licensee's corrective action program as

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LER 50-461/97009.

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The licensee determined that this event occurred due to the failure to provide adequate documentation in the original evaluations which were used to create the RCIC system

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TS Surveillance Requirement acceptance criteria. In response to this issue, the licensee provided training to all engineering personnel, completed calculations for the acceptance criteria which required the incorporation of additional tolerances, and revised the TS Bases to document whether instrument inaccuracies have or have not

been considered in each TS value. The licensee also completed a review of all TS Surveillance Requirement parameters to ensure that all components were adequately tested as required by TSs.

The inspectors reviewed the licensee's CR written as part of the instrument inaccuracy review, ensured that the procedure changes were made when required, and reviewed the safety evaluation written to incorporate instrument inaccuracies into the RCIC system pump surveillance procedure. The inspectors evaluated the results of the

licensee's review of surveillance tests as p' art of the closeout activities for NRC Manual Chapter 0350 Case Specific Checklist item VI.1, " Provide Reasonable Assurance that Safety-Related Structures, Systems, and Components Will Perform Their intended Safety Functions as Described in the Design and Licensing Basis." The inspector's findings and conclusions regarding this issue are documented in Inspection Report 50-461/1999006. The inspectors considered the licensee's corrective actions adequate.

E8.6 (Closed) LER 50-461/97010-00/01: Incorrect Voltage in Procedure for Verification of Offsite Power Sources. In 1992, a concern was raised throughout the nuclear power industry regarding degraded voltage protection. Illinois Power engineers began a study of the effects of degraded voltage on safety-related 120 Vac equipment loads. This study involved a review of the calculations used to establish the minimum bus voltage required to ensure proper operation of safety-related 120 Vac equipment. During a review of these calculations, plant engineers determined a new minimum voltage value was required to be present at the offsite power sources. To address this issue, the licensee revised Procedures 9082.01, " Electrical Distribution Verification Mode 1,2,

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and 3," and Procedure 9082.02, " Electrical Distribution Verification Mode 4 and 5," to j

include the new calculated minimum voltage value. Procedure 5008.05, " Annunciator j

Procedure for Alarm Panel 5008 Row 5, Safety-Related 4Kv Bus Voltage," was also i

i revised to include the new minimum voltage values. In addition, the licensee completed the installation of a modification designed to minimize the affects of degraded voltage at the facility. The inspectors completed a review of this issue as part of the closeout actions for CSC ltem IV.4, " Resolve Degraded Voltage and Electrical Distribution Concerns," and included the results in Inspection Report 50-461/1999011.

E8.7 (Closed) LER 50-461/97034: Incorrect Cable Resistance and Brake Horsepower Data i

Used in the Design of Division I and 11 EDG Room Ventilation Fans Results in Fan Motors Being Outside the Design Basis. On October 23,1997, engineering personnel identified that at least five attemating current (AC) and direct current (DC) calculations used resistance data for uncoated copper conductors rather than for tin-coated copper conductors. The licensee initiated CR 1-97-10-414 to document this issue. This issue was also reported under 10 CFR Part 21.

Design basis calculation 19-AK-02, " Loss of Coolant Accident Block Start Transient Analysis," requires that the EDG room ventilation fans start and accelerate to full speed within 13 seconds during a loss of coolant accident (LOCA). During the CR

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investigation, engineering personnel identified that the Division I and ll EDG room ventilation fans may not meet the 13-second starting requirement under certain conditions. The orlainal brake horsepower calculation for the EDG room ventilation fans assumed the fans operated at a temperature of 96 degrees. Through a subsequent analysis, the licensee determined that: 1) the cabling for the vent fans contained tin-coated copper conductors; 2) the fans operated at temperatures much lower than 96 degrees; 3) brake horsepower increases as temperature decreases; 4) the combination of increased cable resistance and brake horsepower may result in the fans failing to achieve full speed within 13 seconds due to inadequate terminal voltage; and 5) the inadequate terminal voltage condition may cause the safety-related buses to transfer from the offsite power supply to the associated EDG during a LOCA coincident with a degraded voltage condition.

The licensee attributed the cause of this issue to two. separate engineering errors. First, the architect engineering standard used during plant construction lacked detail in that it did not identify and quantify cable construction and installation information which affected resistance and reactance values used in subsequent calculations. In addition, the brake horsepower rating for the EDG room ventilation fans were based on a less conservative temperature rather than the minimum design temperature. The licensee determined that both errors were due to engineering oversight.

Criterion lll to 10 CFR Part 50, Appendix B, states that measures shall be established to assure that design basis information is correctly translated into specifications, drawings, procedures, and instructions. The failure to establish measures to assure that design basis information was correctly translated into specifications for the EDG room ventilation fans was considered to be a violation of 10 CFR Part 50, Appendix B, Criterion lil. This Severity Level IV violation is being treated as a Non-Cited Violation (NCV 50-461/98012-09(DRP)), consistent with Appendix C of the NRC Enforcement Policy. This violation is in the licensee's corrective action program as LER 50-461/97034.

In response to this issue, the licensee developed an independent cable resistance i

standard, revised the architect engineering standard to indicate that the standard should not be used when determining plant specific cable resistance values, corrected electrical calculations to reflect the correct resistance values for tin-coated copper conductors, and sampled the remaining architect engineering standards for accuracy, preciseness, and proper plant specific application. In addition, the licensee installed a modification to delay the start of the EDG room vent fans during a LOCA and prevent the transfer of the safety-related buses. The inspectors reviewed the licensee's corrective actions as part of their on-site review of this issue and had no concems. The inspectors considered the licensee's corrective actions adequate.

E8.8 (Closed) LER 50-461/98006: Incorrect Calculation in EDG Control Circuitry Results in insufficient Voltage and Inoperability of the Division i EDG. During a review of EDG control circuitry, engineering personnel identified a discrepancy in a DC voltage calculation for the Division l EDG control panel. Specifically, the calculation did not include the existence of two cables routed to the remote shutdown panel and their effect on the voltage drop to the EDG control panel. Engineering personnel evaluated this condition and determined that the Division i EDG was inoperable since adequate DC voltage was not available at the EDG control panel to power all associated support equipment. In addition, the licensee determined that this condition may have prevented

• the EDG from starting when required. The licensee initiated CR 1-98-01-452 to document this condition and reported the issue under 10 CFR Part 21. The Division 11 EDG was not impacted by this condition since the associated cabling was not routed to the remote shutdown panel.

Technical Specification 3.8.1, "AC Sources Operating," requires three EDGs to be operable while operating in Modes 1,2, or 3. The failure to have adequate DC power at the Division i EDG control panel to assure continued operability of the Division i EDG and the associated support equipment while operating in Modes 1,2, and 3 was considered to be a violation of TS 3.8.1. This Severity Level IV violation is being treated as.a Non-Cited Violation (NCV 50-461/98012-10(DRP)), consistent with Appendix C of the NRC Enforcement Policy. This violation is in the licensee's corrective action program as LER 50-461/980006.

The licensee attributed the cause of this event to the failure of the architect engineer to adequately address all voltage drops during the preparation of calculation 19-D-28,

" Review of Division i DC System 1A." Lack of attention-to-detail also contributed to this issue in that engineering personnel did not identify any errors in calculation 19-D-28 for over 10 years even though the calculation was revised multiple times.

In June 1998, the licensee installed a design change to reduce the length of cabling between the Division i EDG control panel and the remote shutdown panel and lower the associated voltage drop. The inspectors reviewed this design change and verified that adequate DC voltage was available at the control panel to power all associated equipment. The licensee also briefed engineering personnel on this issue, reviewed other calculations to ensure that all cabling was accounted for in voltage drop calculations and verified that adequate voltage was available for equipment operation.

The inspectors reviewed the licensee's corrective actions during their on-site review and considered them adequate.

E8.9 (Closed) LER 50-461/98007: Inadequate Engineering Evaluation Leads to Installation of Temporary Modification on the DC Electrical Power Stem Which Caused System to be Inoperable When Required to be Operable by TSs. Engineering personnel determined that on March 22,1998, a temporary modification cross connected the non-Class 1E battery charger with the safety-related DC electrical power bus to maintain DC

- bus operability while irradiated fuel was moved in the primary or secondary containment.

It was also determined that the setpoint for the high voltage shutdown card in the battery charger was not low enough to protect the safety-related direct current bus from an over voltage condition and that the card was not a class IE component.

Technical Specification 3.8.5, " Direct Current Sources-Shutdown," required that the direct current electrical power distribution systems be operable during the movement of irradiated fuel inside primary or secondary containment. The failure to provide adequate over voltage protection for the safety-related direct current bus during fuel movements resulted in the bus being inoperable. This is a violation of TS. This Severity Level IV

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violation is being treated as a Non-Cited Violation (NCV 50-46%i98012-11(DRP)),

I consistent with Appendix C of the NRC Enforcement Policy. This violation is in the licensee's corrective action program as LER 50-461/98007.

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The licensee completed a root cause analysis and determined that engineering misjudgement and a lack of attention to detail contributed to this event. Specifically, the

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system engineer that completed the. safety evaluation for the temporary modification failed to verify that the over voltage protection provided by the nonsafety-related battery charger was consistent with the design of the over voltage protection for the direct current bus. In addition, the assumptions made by the safety evaluation preparer were not adequately challenged by the reviewer.

The inspectors reviewed the revised safety evaluation for the temporary modification and the licensee's corrective actions to improve the safety evaluation program. No concerns were identified. The inspectors considered the licensee's corrective actions adequate.

t-E8.10 (Closed) LER 50461/98008: Division l Hydrogen and Oxygen Analyzer incapable of Meeting Design Basis Due to Excessive Vibration. Licensee Event Report 50461/93001 documented that the hydrogen and oxygen analyzers were unable to accomplish their design basis function due to design deficiencies. The licensee implemented a modification to correct the design deficiencies. On March 10,1998, the System Design and Functional Validation (SDFV) team identified that the post-modification testing for the modification was inadequate. The team determined that vibration monitoring was not completed before declaring the hydrogen and oxygen analyzers operable.

On March 25,1998, the licensee completed 24-hour operability tests on the Division I and ll hydrogen and oxygen analyzers to determine if the analyzers could meet their design basis requirements. The test results demonstrated that the Division il analyzer

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was operable since it was capable of meeting its design basis requirements. However, the Division I analyzer experienced excessive vibrations which resulted in it being unable to accomplish its design basis function. The excessive vibration on the Division I analyzer was not required to be evaluated by engineering personnel. The licensee determined that the failure to appropriately evaluate the vibration data was an inadequate post-modification test on the Division I hydrogen and oxygen analyzer and resulted in the analyzer being inoperable since 1993. As a result, the licensee was unable to demonstrate compliance with TS 3.3.3.1, " Post Accident Monitoring Instrumentation," which required two channels of hydrogen and oxygen analyzers to be operable while in Mode 1 or 2. This is a violation of TS 3.3.3.1. This Severity Level IV l

violation is being treated as a Non-Cited Violation (NCV 50461/98012-12(DRP)),

consistent with Appendix C of the NRC Enforcement Policy. This violation is in the licensee's corrective action program as LER 50461/98008.

The licensee determined that the failure to properly test the hydrogen and oxygen analyzers was caused by personnel error. The modification was inappropriately classified as a type IV modification per Nuclear Station Engineering Department

Procedure D.55, " Modification and Configuration Change Control," rather than a type ill modification. Type IV modifications were considered limited scope modifications that did not require work, testing, or release for operation reviews by the system engineer, the project engineer, or the shift supervisor. The inspectors verified that the practice of allowing modifications to be implemented without prior review by engineering and operations was corrected by the implementation of Procedure 1003.01, " CPS Hardware Change Program."

The licensee corrected the high vibration condition on the Division I hydrogen and oxygen analyzer before startup. In addition, the licensee reviewed previously completed

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type IV modifications to ensure that the modifications were properly classified and to

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verify that post-maintenance testing was completed. No deficiencies were identified.

j The requirements of Procedure 1003.01 were also reviewed to verify that adequate barriers existed in the modification process to ensure that required post-maintenance testing was completed before closing a modification package. The inspectors verified the licensee's corrective actions and considered the actions adequate.

E8.11 (Closed) LER 50-461/98009 Failure to Adequately Account for Design Basis System Pressures and Voltages for the Emergency Diesel Generator (EDG) Air Start System

' Leads to a Condition Outside the Design Basis of the Plant. On January 30,1998, engineering personnel reviewed a 10 CFR Part 21 notification from Engine Systems, Incorporated and determined that the EDGs may be unable to perform their intended safety functions under certain conditions due to excessive air start solenoid valve spring force.

The springs in the air start solenoid valves for the Division I and 11 EDGs were changed from 200 psig springs to 275 psig springs in 1986 to prevent excessive air start receiver

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leakage. However, the air start solenoid valves for the Division I and 11 EDGs were not tested at design basis conditions following the spring replacement due to an oversight

by the responsible design engineer. The springs on the Division 111 EDG were replaced with 275 psig springs in December 1992 in response to a previous 10 CFR Part 21 notification from the engine's manufacturer. These valves also were not tested due to engineering oversight.

in response to this issue, the licensee conducted design basis testing on twu solenoid i

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valves in storage and four solenoid valves installed on the Division il EDG. The test results showed that the valves taken from storage operated successfully under design j

basis conditions. However, the valves installed on the EDG failed to actuate reliably

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below air start system pressure Of 165 psig. Technical Specification action statements allowed the EDGs to be operable at 140 psig as long as it was restored to 200 psig i

within 48 hours5.555556e-4 days <br />0.0133 hours <br />7.936508e-5 weeks <br />1.8264e-5 months <br />. It was unlikely that both Division I and ll EDGs would have low air pressure at the same time. Further, the pressure in the Division I and ll air receivers is automatically controlled between 215 and 250 psig. The failure to maintain the Division I and II EDGs operable for all design basis conditions is a violation of TS 3.8.1,

"AC Sources-Operating," while in Mode 1, 2, or 3, and TS 3.8.2, "AC Sources-Shutdown," while in Mode 4 or 5. This Severity Level IV violation is being treated as a Non-Cited Violation (NCV 50-461/98012-13(DRP)), consistent with Appendix C of the NRC Enforcement Policy. This violation is in the licensee's corrective action program as LER 50-461/98009.

On June 17,1998, the licensee replaced the 275 psig springs in the Division 111 EDG air start solenoid valves with 230 psig springs. The licensee also replaced the existing air start solenoid valves for the Division I and II EDGs with new valves which supported operation at design basis conditions. The inspectors reviewed the Part 21 notification, the installation of the 230 psig springs on the Division ill EDG, and the installation of the new valves on the Division I and II EDGs as part of their on-site review. No new concerns were identified.

E8.12 (Closed) LER 50-461/98010: Inoperable Division I and ll Hydrogen and Oxygen Analyzers Due to inadequate Commercial Grade Dedication of Safety-Related Replacement Parts By Supplier. While reviewing an audit of a supplier's quality

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assurance (QA) program, the licensee's QA department determined that commercial grade replacement parts for the Division I and il hydrogen and oxygen analyzers were approved using an inadequate commercial grade dedication program. The licensee reviewed a list of parts which were dedicated using the deficient program and determined that several of the replacement parts were installed in the analyzers. Since the quality of these parts was indeterminate, the drywell and containment hydrogen and oxygen analyzers were outside the design basis of the plant and were declared inoperable. This issue was reported under 10 CFR Part 21.

Technical Specification 3.3.3.1 requires that two hydrogen and oxygen analyzers be operable while in Mode 1 or 2. The licensee was unable to demonstrate compliance with this TS requirement since the analyzers were outside the design basis of the plant due to the installation of improperly dedicated replacement parts. This is a violation of TS 3.3.3.1. This Severity Level IV violation is being treated as a Non-Cited Violation (NCV 50461/98012-14(DRP)), consistent with Appendix C of the NRC Enforcement Policy. This violation is in the licensee's corrective action program as LER 50-461/98010.

The licensee attributed the cause of this event to the supplier's failure to develop a commercial grade dedication program for items used in safety-related applications as required by Appendix B to 10 CFR Part 50. The licensee implemented corrective actions to prevent unqualified material from being purchased and installed in the plant.

The licensee evaluated installed material in the analyzers and replaced unqualified material. The licensee placed an administrative hold on all stored equipment that was purchased from the supplier until the material was evaluated for acceptability. The licensee also placed a restriction on purchasing material from this supplier without first providing evidence that the materials were properly dedicated, and reviewing the process used by the licensee's quality assurance department to qualify suppliers of j

safety-related materials. The inspectors reviewed the licensee's corrective actions for this issue during the closeout activities for NRC Manual Chapter 0350 Case Specific Checklist item V.2, " Provide Reasonable Assurance that Qualified Materials and Parts are Installed in Plant Systems." The inspectors' conclusions regarding this issue are

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documented in inspection Report 50-461/1999006.

E8.13 (Closed) LER 50-461/98011: Control Room Ventilation System inoperable Due to Broken or Missing Conduit Hold Down Restraints on VC Chiller Skids. On September 22,1997, the licensee identified that the control room ventilation (VC)

system was inoperable due to broken or missing conduit hold down restraints on the A train chiller skids. On January 28,1998, maintenance personnel identified that several conduit hold down restraints were missing or broken on the B train chiller skids.

l During the review of this issue, engineering personnel determined that the seismic

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qualification of both VC chillers may have been adversely affected due to the missing hold down restraints. The licensee determined that the failure to maintain the seismic qualifications for the VC chillers resulted in the VC system being inoperable since

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April 1995. This was a violation of TS 3.7.4, " Control Room Air Conditioning Systems,"

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which required two VC subsystems to be operable while in Mode 1,2, or 3. This Severity Level IV violation is being treated as a Non-Cited Violation (NCV 50461/98012-15(DRP)), consistent with Appendix C of the NRC Enforcement Policy. This violation is in the licensee's corrective action program as LER 50-461/98011.

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The licensee determined that the broken or missing restraints constituted a maintenance preventable functional failure since the broken restraints were caused by personnel walking or climbing on the VC chillers during inspection and maintenance activities. The licensee revised Site Safety Standard 10, " Personnel Protective Equipment," to provide guidance to personnel regarding the use of equipment as climbing aids. The conduit hold down restraints on the VC A train chiller were replaced on October 17,1997. The hold down restraints on the B train chiller were replaced on May 1,1998. The inspectors reviewed the licensee's implementation of the corrective actions and had no concems.

E8.14 (Closed) LER 50-461/98012: High Differential Pressure Required to Close Excess Flow Check Valves Being Outside the Design Basis of the Plant. On May 11,1998, the licensee determined that the plant was in a condition outside the design basis relating to Regulatory Guide 1.11. " Instrument Lines Penetrating Primary Reactor Containment,"

and did not meet TS 3.6.1.3, " Primary Containment Isolation Valves" since receipt of the Operating License on September 29,1986. This condition resulted from primary containment isolation excess flow check valves 1CM051 and 1CM053 being equipped with poppet springs requiring a closing differential pressure greater than maximum peak drywell pressure expected during a design basis loss of coolant accident. Specifically, the licensee identified that five instrument line's excess flow check valves connected to the containment atmosphere failed to close at a differential pressure less than the expected peak containment accident pressure. In addition, an instrument line excess flow check valve connected to the drywell atmosphere also failed to close at a differential pressure less than the expected peak drywell accident pressure.

The licensee determined that the five excess flow check valves connected to the containment atmosphere failed to pass surveillance testing due to errors in the testing methodology. The incorrect test methodology is considered a TS 3.6.1.3 violation of minor significance and is not subject to formal enforcement action. Once the testing l

methodology was corrected, the licensee demonstrated that the excess flow check valves connected to the containment atmosphere would close at a pressure less than the peak containment accident pressure and met the requirements of TSs 3.6.1.3. The revised excess flow check valve testing methodology was inccrporated into Procedure 9864.01, " Excess Flow Check Valve Operability Test." The inspectors reviewed the licensee's corrective actions and considered them adequate.

E8.15 (Closed) LER 50-461/98016: Failure to Test Vsdves 1SX013D/E/F in Accordance with the In-Service Testing Program Due to Personnel Error. On March 2,1998, the licensee identified that shutdown service water system pump discharger strainer valves 1SX013D, -E, and -F were not tested as required by the in-service test program. On June 30,1987, engineering personnel removed the shutdown service water system pump discharge strainer valves from the in-service testing program based on an evaluation that stated that the valves lacked an active safety function. On March 2, 1998, the System Design and Functional Validation (SDFV) team and engineering personnel identified that the valves had been removed from the program in error. The team also identified that these valves were required to be functiona'ly tested by TS 5.5.6, "In-service Testing Program."

i Technical Specification 5.5.6 required that in-service testing be performed on all ASME Code Class 1,2, and 3 components per Section XI of the ASME Boiler and Pressure Vessel Code.Section XI of the ASME Code states, in part, that valves required to

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perform a specific function in shutting down the reactor to a cold shutdown condition, or mitigating the consequences of an accident, should be included in the IST program.

Omitting these valves from the in-service testing program and not doing functional testing is a violation of TS 5.5.6. This Severity Level IV violation is being treated as a Non-Cited Violation (NCV 50 461/98012-16(DRP)), consistent with Appendix C of the NRC Enforcement Policy. This violation is in the licensee's corrective action program as i

LER 50-461/98016.

In response to this issue, the licensee satisfactorily tested valves 1SX013D, -E, and -F per TS and ASME requirements, added the valves to the IST program, and reviewed all other valves that were removed from the IST program in 1987 to ensure that the removal was appropriate. The licensee also planned to incorporate valves 1SX013D,

' E, and -F into USAR Table 3.9-5, " Balance of Plant Active Valves and Pumps." The

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inspectors considered the licensee's corrective actions to be adequate.

E8.16 (Closed) LER 50-461/98019: Inadequate Surveillance Procedure i.eads to Failure to Satisfy TS for Ensuring Electrical Loads Properly Sequence Onto the Safety-Related Buses. Technical Specification Surveillance Requirement 3.8.1.18, requires that the proper sequencing of electrical loads on the Division I and 11 safety-related busses after a loss of offsite power be verified every 18 months. Procedures 9080.21, " Diesel Generator 1 A-ECCS Integrated," and 9080.22, " Diesel Generator 1B-ECCS Integrated,"

are used to verify proper load sequencing onto safety-related busses. However, these

procedures did not verify the sequence time of the main control room ventilation supply and return fan electrical loads onto the Division I and il safety-related electrical buses.

The acceptance criteria for these loads to sequence onto the safety-related electrical buses is between 36 and 44 seconds. When tested, the Division 11 control room supply and return fan load sequenced onto the safety-related bus at 45.30 and 45.48 seconds respectively. After troubleshooting, the supply and retum fan load sequencing was tested satisfactorily. The failure to properly transfer TS SR 3.8.1.18 into plant procedures is a violation of Criterion V, " Instructions, Procedures, and Drawings," to Appendix B, " Quality Assurance for Nuclear Power Plants and Fuel Reprocessing Plants," to 10 CFR Part 50. This Severity Level IV violation is being treated as a

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Non-Cited Violation (NCV 50-461/98012-17(DRP)), consistent with Appendix C of the NRC Enforcement Policy. This violation is in the licensee's corrective action program as LER 50-461/98019.

In addition to the example described above, the licensee also completed a review of the testing methodology and acceptance criteria for all TS surveillance requirements. The inspectors reviewed the results of the licensen's review of its surveillance tests as part of the closeout activities for NRC Manual Chapter 0350 Case Specific Checklist item VI.1,

" Provide. Reasonable Assurance that Safety-Related Structures, Systems, and Components Will Perform Their Intended Safety Functions as Described in the Design

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and Licensing Basis." The inspectors documented their findings in Inspection Report 50-461/1996006. No additional concems were identified.

E8.17 (Closed) LER 50-461/98026: Incorrect Supplier Design Results in inoperable Electric Power Assembly (EPA) Circuit Cards that Monitor Power to the Reactor Protection System (RPS) Scram and Main Steam Isolation Valve (MSIV) Solenoids. This event involved a 10 CFR Part 21 notification that stated that the EPA circuit cards were not designed or built to the original design specification. Specifically, the EPA cards did not provide adequate protection for the RPS electric power monitoring system since they j

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were unable to trip within 4 seconds in response to an over/under voltage or an over frequency condition. The failure of an EPA circuit card to trip within the designed time delay can result in long term degradation of the solenoid valves due to overheating or cause mechanical degradation due to solenoid chatter.

Technical Specification 3.3.8.2, " Reactor Protection System Electric Power Monitoring,"

requires that one RPS electric power monitoring assembly shall be operable for each in service RPS special solenoid power supply or alternate power supply. The failure to install EPA circuit cards that meet the design requirements associated with protection of the RPS electric power monitoring system is a violation of TS 3.3.8.2. This Severity Level IV violation is being treated as a Non-Cited Violation (NCV 50-461/98012-18(DRP)), consistent with Appendix C of the NRC Enforcement Policy. This violation is in the licensee's corrective action program as LER 50-461/98026.

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The licensee's corrective actions included, in part, the procurement of new EPA circuit cards that met the design specifications, installation of the new EPA circuit cards before l

- restart of the facility, and testing of installed solenoid valves for degradation. No degradation was identified during testing. The inspectors considered the licensee's corrective actions adequate.

E8.18 (Closed) LER 50-461/98032: Exc?ssive Voltage Drop in the Control Circuit for the Division 111 EDG Output Circuit Breaker Results in the Plant Being Outside the Design Basis. While reviewing battery calculations as part of the corrective actions for LER 50-461/98-006, the licensee identified that the control circuit for the Division 111 EDG output circuit breaker exceeded 3000 feet. Due to the circuit length, the licensee questioned the adequacy of the current voltage drop calculation and whether adequate

. DC voltage was available at the output breaker's closing coil to ensure that the breaker would close when required. During a subsequent review, engineering personnel determined that calculation 19-D-27, " Review of Division ll1 DC System 1C," had not considered the circuit length. When the length was considered, the licensee identified that adequate DC voltage may not have been available to ensure that the Division ll1

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EDG and the high pressure core spray system would have initiated in response to a loss of offsite power event. Condition Report 1-98-01-452 was initiated to document this event. This issue was also reported under 10 CFR Part 21.

The licensee determined that this issue occurred due to two errors. During initial plant construction, the architect engineer failed to recognize the impact of the excessive circuit length on the voltage applied to the breaker's closing coil. As a result, this information was not included during the development of design basis calculations for the Division 111 EDG output breaker. In addition, engineering personnel failed to identify the impact of the excessive circuit length during subsequent revisions to calculation 19-D-27. The inspectors determined that the failure to establish measures to assure that design basis information was correctly translated into specifications for the Division 111 EDG output breaker was a violation of 10 CFR Part 50, Appendix B, Criterion 111. This Severity Level IV violation is being treated as a Non-Cited Violation (NCV 50-461/98012-19(DRP)), consistent with Appendix C of the NRC Enforcement Policy. This violation is in the licensee's corrective action program as LER 50-461/98032.

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On February 28,1999, the licensee installed a design change which reduced the Division 111 EDG control circuit length to ensure that adequate voltage was available to the output breaker's closing coil. The inspectors reviewed this design change and had no concems. In addition, the licensee briefed engineering personnel on this issue and

- revised the architect engineering standard to ensure that users were aware of potential impacts due to excessive circuit lengths. The inspectors considered the licensee's corrective actions adequate.

IV. Plant Suncort

.R1 Radiological Protection and Chemistry (RP&C) Controls R1.1 Radioactive Liauid Soill(71750)

On August 23,1999, a contaminated liquid spill occurred during maintenance on the Div-2 SX system to RHR system cross connect piping. Maintenance personnel attempted to catch the water in a plastic bag and transfer it to a floor drain. However, one of the worker's shoes became contaminated as revealed by a whole body frisker which alarm id as the worker attempted to exit the radiologically controlled area.

' Radiation protection (RP) personnel were not present at the job site when the system was opened and the water was transferred to the floor drain. After the personnel monitor alarmed, RP personnel actively pursued the cause of the contamination. The control room was not notified of the spill until about 2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br /> after the occurrence. Once notified, the control room operators entered off normal Procedure 4979.06, " Radioactive Spill," and exited it after ensuring that the spill had been cleaned up. The inspectors concluded that the workers and radiation personnel handled the spill appropriately but were slow in notifying the control room of the spill.

R1.2 Power Reduction Results in increased Dose Savinas Durina Water-Box Cleanina a.

Inspection Scooe (71750)

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The inspectors assessed the licensee's actions to maintain radiological dose as low as reasonably achievable (ALARA) during the cleaning of both condenser water boxes.

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Observations and Findinas The inspectors observed that licensee management closely monitored the radiation dose expended during condenser water box cleaning. During the initial cleaning stages, licensee management identified that higher than expected doses were being expended due to the considerable amount of debris in the water boxes. In response to this observation, an ALARA meeting was beld and licensee management determined that significant dose savings could be realized if reactor power was lowered from 50 percent to 45 percent. Following the ALARA meeting, reactor power was lowered to 45 percent for the remainder of the water box cleaning. The licensee determined that the decision to lower reactor power resulted in a dose savings of approximately 30 percent.

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Conclusions The inspectors determined that licensee management effectively used ALARA -

techniques to minimize radiation dose during the cleaning of the condenser water boxes. Specifically, an additional five percent reactor power reduction resulted in about 30 percent dose savings.

V. Management Meetinas X1 Exit Meeting Summary The inspectors presented the inspection results to members of licensee management at the -

conclusion of the inspection on September 8,1999. The licensee acknowledged the findings presented. The inspectors asked the licensee whether any materials examined during the inspection should be considered proprietary. No proprietary information was identified.

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PERSONS CONTACTED I

Licensee i

M. Coyle, Assistant Vice President K. Gallogly, Director, Corrective Action J. Goldman, Manager, Work Management P. Hinnenkamp, Clinton Plant Manager W. Maguire, Director - Operations J. McElwain, Chief Nuclear Officer M. Moore, Manager, Quality Assurance R. Phares, Manager, Nuclear Safety and Performance improvement A. Plater, Director, Plant Radiation and Chemistry

' R. Schenck, Manager, Maintenance D. Smith, Director, Security and Emergency Planning.

D. Warfel, Manager, Nuclear Station Engineering Department INSPECTION PROCEDURES USED IP 37551:

Engineering Observations IP 61726:

Surveillance Observations IP 62707:

Maintenance Observation IP 71707:

Plant Operations'

IP ~71750:

Plant Support and Observations IP 92700:

Onsite Followup of Written Reports of Nonroutine Events at Power Reactor Facilities IP 92903:.

Followup - Engineering l

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ITEMS OPENED, CLOSED, AND DISCUSSED Opened 50-461/98012-01 NCV Failure to verify attemate decay heat removal source

50-461/98012-02 NCV Failure to restore reactor coolant circulation within the TS required time i

50-461/98012-03'

NCV Technical Specification 3.8.9 " Distribution System - Operating,"

y and 3.8.10, " Distribution System - Shutdown." were not met 50-461/98012-04 NCV main steam isolation valves' closure times were outside of TS requirements due to procedural inadequacy 50-461/98012-05 NCV Failure to immediately begin work on the essential switchgear heat removal system violated TSs 3.8.2 and 3.8.5 50-461/98012-06 NCV Failure to complete a integrity test resulted in the secondary containment being inoperable during core alterations 50-461/98012-07 NCV Inadeonate surveillance test procedure resulted in residual heat removai heat exchanger shell vent valves not being tested 50-461/98012-08 NCV Surveillance procedure did not adequately consider accuracy of installed instrumentation in meeting TS requirements for the RCIC

pump 50-461/98012-09 NCV Failure to ensure design basis information for EDG room ventilation fan motors were included in specifications l

l 50-461/98012-10 NCV Violation of TS 3.8.1 by not assuring adequate DC power for the Division l EDG control panel -

50-461/98012-11 NCV Inadequate over voltage protection for the safety-related direct current bus during fuel movements 50-461/98012-12 NCV Failure to implement modification control procedure 50-461/98012-13 NCV Failure to maintain the Division I and 11 EDGs operable for all

design basis condit;cns 50-461/98012-14 NCV Inoperable Division i and 11 hydrogen and oxygen analyzers due to i

inadequate commercial grade dedication 50-461/98012-15 NCV Failure to maintain the seismic qualifications for the VC chillers 50-461/98012-16 NCV Shutdown service water pump discharger strainer valves not in i

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50-461/98012-17 NCV Failure to transfer TS Surveillance Requirement 3.8.1.18 into plant procedure 50-461/98012-18 NCV Failure to install EPA circuit cards that meet the design requirements associated with protection of the RPS electric power monitoring system 50-461/98012-19 NCV - Failure to transfer design basis information into specifications for the Division ll EDG output breaker 50-461/99014-01 NCV_ Failure to place OOS switch in INOP 50-461/99014-02 URI _ Div-2 EDG inoperability due to diluted lube oil 50-461/99014-03 NCV Providing unclear instructions for FIN Team safety tagouts Closed 50-461/96014 LER inadequately tested auxiliary building roof plug leads to secondary containment inoperability 50-461/96015 LER Lack of attention to detail during procedure completion causes unplanned engineered safety features actuation of eight containment isolation valves 50-461/96019 LER Inadequate surveillance procedures due to misinterpretation of TS bases results in source range monitor reactor period display not verified operable 50-461/96020 LER Failure of control rod drive hydraulic air line due to over tightening fitting during maintenance 50-461/97003-LER Failure to recognize the impact of disconnecting the Division i IRM while the Division ll lRM was disconnacted 50-461/97004 LER Inadequate procedure leads to failure to properly implement TS surveillance requirement 3.6.5.3.3 50-461/97009 LER Surveillance procedure did not adequately consider accuracy of installed instrumentation in meeting TS requirements for reactor core isolation cooling pump.

50-461/97010 LER Incorrect voltage in procedure for verification of offsite power sources 50-461/97011 LER Failure to verify breaker closed a 7-day frequency as required by TS 50-461/97014-LER Main steam isolation valve closure time outside of TSs due to procedure inadequacy

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50-461/97034 LER Incorrect cable resistance and brake horsepower data used in the

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design of Division I and ll EDG room ventilation fans results in fan motors being outside the design basis

. 50-461/97036 LER Failure of cooling unit manufacturer to install motor shaft key leads to inoperable of SX pump room cooling unii 50-461/98002-LER Loss of service air results in unplanned engineered safety features actuation and manual reactor scram 50-461/98006 LER Incorrect calculation in EDG control circuitry resuF in insufficient

. voltage and inoperability of the Division i EDG 50-461/98007 LER inadequate engineering evaluation leads to installation of temporary modification on the Direct current electrical power system 50-461/98008 LER Division I hydrogen and oxygen analyzer incapable to meeting design basis due to excessive vibration on air compressor 50-461/98009 LER Failure to adequately account for design basis sys tem pressures and voltages for the EDG air start systems 50-461/98010 LER inoperable Division I and ll hydrogen and oxygen analyzers due to inadequate commercial grade dedication of safety-related replacement parts by supplier 50-461/98011 LER Control room ventilation (VC) system inoperabe -

.o broken or missing conduit hold down restraints on VC chiller skids 50-461/98012 LER High differential pressure required to close excess flow check valve results in valve being outside design basis of the plant 50-461/98016 LER Failure to tetst valves SX pump discharger strainer valves 1SX013D, -E, and -F per the IST program 50-461/98018 LER Engineered safety features actuation caused by deficiencies in method used to complete NSPS power supply adjustments 50-461/98019 LER Inadequate surveiliance procedure leads to failure to satisfy TS for ensuring electrical loads properly sequence on to the safety-related buses 50-461/98020 LER Inadequate flow balancing of SX system results in less than required flow to SX loads

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-50-461/98026 LER Incorrect supplier design results in inoperable EPA circuit cards that monitor power to the RPS scram valve and MSIV solenoids.

50-461/98033 LER Inappropriate clearing of a caution tagout results in TS 3.4.10, Action A.1 not being met.

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'50/461/98032 LER Excessive vohage drop in the control circuit for the Division ill

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EDG output circuit breaker results in the plant being outside the

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design basis 50-461/98035 LER Failure to comply with TS action requirements to immediately j

restore AC and Direct current electrical power sources.

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50-461/98036 LER Opening incorrect electrical cubicle caused loss of shutdown cooling and leads to failure to meet TS required action in the required time 50-461/96412-29 VIO Inadequate testing of feedwater check valves.

50-461/96412-30 VIO Inadequate corrective actions for feedwater check valves.

'50-461/98012-01 NCV Failure to verify attemate decay heat removal source i

50-461/98012-02 NCV Failure to restore reactor coolant circu'ation within the TS required j

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50-461/98012-03 NCV Technical Specification 3.8.9 " Distribution Syctem - Operating,"

j and 3.8.10, " Distribution System - Shutdown," were not met 50-461/98012-04 NCV Main steam isolation valves' closure times were outside of TS requirements due to procedural inadequacy 50-461/98012-05 NCV Failure to immediately begin work on the essential switchgear heat removal system violated TSs 3.8.2 and 3.8.5 50-461/98012-06 NCV Failure to complete a integrity test resulted in the secondary containment being inoperable during core alterations 50-461/98012-07 NCV Inadequate surveillance test procedure resulted in residual heat removal heat exchanger shell vent valves not being tested 50-461/98012-08 NCV Surveillance procedure did not adequately consider accuracy of installed instrumentation in meeting TS requirements for the RCIC pump 50-461/98012-09 NCV Failure to ensure design basis information for EDG room ventilation fan motors were included in specifications 50-461/98012-10 NCV Violation of TS 3.8.1 by not assuring adequate DC power for the Division l EDG control panel 50-461/98012-11 NCV Inadequate over voltage protection for the safety-related direct current bus during fuel movements 70-461/98012-12 NCV Failure to implement modification control procedure

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50-461/98012-13 NCV Failure to maintain the Division I and II EDGs operable for all design basis conditions 50-461/98012-14 NCV Inoperable Division I and ll hydrogen and oxygen analyzers due to inadequate commercial grade dedication 50-461/98012-15 NCV Failure to maintain the seismic qualifications for the VC chillers 50-461/98012-16 NCV Shutdown service water pump discharger strainer valves not in IST program 50-461/98012-17 NCV Failure to transfer TS Surveilli1ce Requirement 3.8.1.18 into plant procedure 50-461/98012-18 NCV Failure to install EPA circuit cards that meet the design requirements associated with protection of the RPS electric power monitoring system 50-461/98012-19 NCV Failure to transfer design basis information ir.to specifications for the Division ll EDG output breaker 50-461/99014-01 NCV Failure to place OOS switch in INOP 50-461/99014-03 NCV Providing unclear instructions for FIN Team safety tagouts Discussed None

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LIST OF ACRONYMS

ALARA As Low As Reasonably Achievable ANSI Americar National Standards Institute CFR Code of Federal Regulation CR Condition Report CRS Control Room Supervisor EDG Emergency Diesel Generator EMF Electro Magnetic Field FIN Fix-it-now HPCS High Pressure Core Spray INOP Inoperable LCO Limiting Condition for Operation MCR Main Control Room MOV Motor-Operated Valve MWO Maintenance Work Order NCV Non-Cited Violation OD Operability Determination OE Operability Evaluation OOS Out-of-service RCIC Reactor Core Isolation Cooling RG Regulatory Guide RHR Residual Heat Removal RP Radiation Protection SX Shutdown Service Water TPD Temporary Procedure Deviation TS Technical Specification VD Diesel Ventilation VG Standby Gas Treatment VOTES Valve Operating Test and Evaluation System

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