IR 05000298/1998007

Insp Rept 50-298/98-07 on 981004-1114.Violations Noted.Major Areas Inspected:Operations,Maint,Engineering & Plant Support

ML20197J744
Person / Time
Site:	Cooper
Issue date:	12/11/1998
From:	NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION IV)
To:
Shared Package
ML20197J704	List: IR 05000298/1998007 ML20197J700 ML20197J732
References
50-298-98-07, 50-298-98-7, NUDOCS 9812150200
Download: ML20197J744 (34)

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e ENCLOSURE 2 U.S. NUCLEAR REGULATORY COMMISSION

REGION IV

Docket No.: 50-298 License No.: DPR 46 Report No.: 50-298/98-07 Licensee: Nebraska Public Power District Facility: Cooper Nuclear Station Location: P.O. Box 98 Brownville, Nebraska Dates: October 4 through November 14,1998 Inspectors: V. Gaddy, Acting Senior Resident inspector C. Skinner, Resident inspector J. Melfi, Project Engineer C. Clark, Reactor inspector C. Paulk, Senior Reactor inspector T. Meadows, Senior License Examiner Approved By: C. Marschall, Chief, Branch C

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Division of Reactor Projects l

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ATTACHMENT: Supplemental Information i

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9812150200 981211 PDR ADOCK 05000298 G PDR i

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EXECUTIVE SUMM ARY Cooper Nuclear Station NRC Inspection Report 50-298/98-07 Operations

The plant shutdown was well-controlled and control room supervision appropriately monitored the activities. Communications were clear and response to plant annunciators were rapid and in accordance with management expectations (Section 01.1).

• The inspectors identified that inadequate communication was the cause of the shift supervisor not knowing what the approved contingency plan was when the plant was in a higher risk evolution. This higher risk evolution existed because primary and secondary containment were not established. Also, the inspectors identified that the licensee had not formally identified the conditions at which approved contingency plans for two higher risk evolutions (loss of vessel temperature control and loss of decay heat removal capability) would be implemented. As a result of the inspectors' observations, the contingency plans were briefed to the shift supervisor and revised to identify the entry conditions (Section 01.2).

The licensee used standing orders as procedures to direct operational activities. Some standing orders contained direction that was different from that in approved procedure Although the standing orders were being used as procedures, they had not been processed in accordance with administrative requirements regarding procedure changes and generations. This precluded important steps or information contained in the '

standing order, but not in the referenced procedures, from being included in plant I procedures (Section O3.1).

• Indicated reactor water level dropped 58 inches when the reactor vessel head vent was removed. During this event, operators failed to question or evaluate the change in i reactor pressure on reactor water level, nor did they calculate the time to reach 180 inches while increasing reactor water level. No increased exposure to workers resulted from the inaccurate water levelindication. The inspectors reviewed the

! licensee's interim corrective actions and found them appropriate to prevent recurrence j l (Section O3.2).  !

• Operations personnel failed to identify during the development and implementation of a l clearance order that Technical Specifications-required postaccident instrumentation was i rendered inoperable. As a result, the limiting condition for operation for the l instrumentation, Technical Specification 3.3.1.1.a, was not entered. Control room l operators noted that the equipment was inoperable hours after the clearance order was hung during a routine control board walkdown. This is a noncited violation of Technical Specification 5.4.1.(Section 04.1).

• During a reset of a reactor scram signal, a licensed operator failed to follow station operating procedures to bypass the scram discharge volume high level trip. This

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resulted in a second reactor scram. A second operator acting as a peer check noted that the operator f ailed to bypass the scram discharge volume high level trip, but

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-2-reasoned that it was not a problem and did not question that operator. Failure of the peer checker to vocalize his concern wau identified as a contributing cause of the scram (Section 04.2).

• The licensee identified that the reactor building suppression chamber vacuum breakers were not tested every 3 months as required due to a misinterpretation of the Technical Specifications. The licensee was testing the vacuum breakers once every 18 months (Section 08.1).

Maintenance

Performance of maintenance activities were well controlled and performed in a step-by-step manner. Plant material condition was also good (Section M1.1).

In 1973, the licensee identified degradation of the internal coating installed in underground piping, such as service water and fire protection systems, and did not implement a program to monitor this degraded condition. The material captured in the strainers which were installed as corrective actions was not being monitored. The licensee's initial troubleshooting activities were performed in an adequate and controlled manner, and the service water system and fire protection system operability determinations were adequate (Section M2.1).

During the outage, the licensee identified instances in which quality control hold points 3 and quality control witness steps were not performed by maintenance personnel. No single cause was identified as the source of the quality control deficiencies, in each instance af ter the licensee realized that the required quality control functions were not performed, the licensee took actions to ensure the quality control functions were performed (Section M7.1).

A violation (50-298/97007-05) was issued with two examples of test procedures that did not provide appropriate test requirements. The licensee's corrective actions did not adequately correct the problem in that the procedure changes caused plant staff to stroke the valves prior to leak testing, thus preconditioning the valves. In response to the newly identified problem, the licensee appropriately corrected the procedure and initiated a condition report to address the cause of the inadequate corrective action The failure to effectively correct the previous example of inadequate test requirements is a violation of 10 CFR Part 50, Appendix B, Criterion XVI (Section M8.1).

Enaineerina

Several inadequacies were identified in the postmodification testing requirements following a modification to the diesel generator output breaker mode selector switc Specifically, the work instructions prepared by engineering did not identify that a contact on a relay in the exciter circuitry was closed which prevented the diesel generator output breaker mode selector switch from being successfully tested. Additionally, the package had ta be revised to address other testing inadequacies identified by the operations personnel (Section E1.1).

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• The development of a work package to correct a wiring error on the overpower relay of

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the diesel generator did not identify that surveillance procedures would be affected by the work. Operations did not identify that the maintenance would prevent the performance of required surveillance testing during their closeout review of the paperwork (Section E1.2).

l * The licensee identified that the current interrupting capability of fuses in the 125 Vdc and l 250 Vdc systems were rated for 10,000 amperes while the calculated fault current was 24,000 amperes. The licensee first identified this in 1990, which incorrectly justified the use of the lower rated fuses, which was consistent with the poor engineering l performance noted at that time. The recent efforts, which resulted in the identification of l this past problem, suggested an improving performance. However, the problems associated with identifying the affected fuses suggested a need for additional attantion l to improve work products provided on short notice. Even though the licensee tested the fuses and demonstrated an interrupting capability of 25,500 amperes, the fu ies were only rated for 10,000 amperes. This was a noncited violation of 10 CFR Part 50, Appendix B, Criterion Ill.(Section E1.3).

• The licensee performed an inadequate postmaintenance test following the replacement of the power supply that supplied power to the scram discharge instrument volume Channel A2 level transmitter. This resulted in the failure of a Channel A2 scram discharge volume high level trip to fail on a valid reactor protection system (RPS)

actuation. The licensee corrected the condition and initiated a problem identification report to address the inadequate test (Section E1.4).

Plant Support

• Performance of multiple tasks outside the scope of the outage position by the lead radiation protection technician was identified as the root cause of an event in which portions of the refueling floor were contaminated and four workers received uptakes of radioactive material. The area became airborne due to not keeping the area wetted as required by the radiation work permit. The calculated committed effective dose equivalent ranged from 2 to 6 mrem. This was a noncited violation of Technical Specification 5.4.1.(Section R1.1).

• During the outage, the licensee identified several instances where workers entered into high radiation areas without signing onto the proper radiation work permit. In each instance the licensee took quick action to remove the workers from the area and verified the dose received by the workers was minimal (Section R1.2).

• After being informed of anomalies with dosimetry, radiation protection personnel responded in a quick manner to identify whether any workers had received dose in excess of administrative limits. No workers had received excessive dose. Radiation protection personnel also worked closely with the sof tware vendor to resolve the anomaly (Section R3.1).

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Report Details Summary of Plant Status On October 3,1998, the licensee placed the plant in Mode 3 (hot shutde"m) and, later that day, in Mode 4 (cold shutdown). On October 5, the plant was placed in Mode 5 (refueling) to begin the 18th refueling outage. The plant remained shut down at the end of the inspection perio . Operations 01 Conduct of Operations

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O Shift Crew Control of Plant Ooerations Insoection Scope (71707)

The inspectors observcd control room activities during the plant shutdown, mode transitions, and outage ' operations. The observations included control room shift changes, daily control room activities, routine watch-standing, and scheduled training activities. The inspectors performed control board walkdowns and observed crew briefing Observations and Findinas Licensed operators performed procedural steps in a sequential and carefully controlled manner. Activities required by procedures were undertaken in a methodical and controlled manner, inspectors observed control room supervisors monitoring testing at intervals of approximately 5 minutes, indicating close supervision and understanding of the significance of reactivity changes during the downpower. Oversight by the shift supervisor was effective. Changes in plant conditions were monitored closely by the operating crews. Communications were clear and response to plant annunciators were rapid and in accordance with management expectation The inspectors observed several shift turnovers. Implementatior. of procedures and control of the outage workload were, with minor exceptions, conducted in a conservative and efficient manner. Tha shift management frequently organized briefings at intervals appropriate to facilitate important or complicated evolutions. The inspectors observed significant oversight by plant operations management. A daily review of control room logs indicated good record keeping, consistent with management expectation Conclusions The plant shutdown was well controlled and con:rol room supervision appropriately monitored the activities. Communications were clear and response to plant annunciators were rapid and in accordance with management expectations.

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2-O1.2 Entry Conditions for Continaency Plans Not Documented Insoection Scope (71707)

The inspectors reviewed the contingency plans developed prior to performing higher risk evolutions to assess their adequacy, and during higher risk evolutions the inspectors verified that the contingency plans were in plac Observations and Findinas On October 10,1998, the inspectors questioned the on-duty shif t supervisor as to what i was the approved contingency plan for the high risk evolution the plant was in. The shift i supervisor stated that he did not know of any contingency plans which were in plac !

During discussions with the outage manager, the inspectors learned that a contingency plan was developed and was concurred on by operations department personnel. The inspectors later learned that some members of the operating crew had been informed of what the approved contingency plan for the plant condition was but, due to inadequate communications, the shift supervisor, who was responsible for implementation, was not made aware of the contingency plan.

i On November 3,1998, licensee management provided the inspectors with an overview l l of their approved contingency plans for planned higher risk evolutions. The contingency )

plans provided direction to be taken if problems were encountered during these evolutions. The inspectors reviewed two approved contingency plans and noted that they did not identify entry conditions. The inspectors asked under what conditions would the plans be implemented. Licensee management stated that the entry conditions were known by those personnel required to implement the contingency plan. The inspectors questioned how licensee management could be confident that contingencies would be implemented if the entry conditions were not specified on the approved plans. The licensee stated that all personnel responsible for implementing the contingency plans were briefed on what the entry conditions were. The inspectors disagreed with the licensee based on the example stated above. As a result, the contingency plans were revised to incorporate entry condition Conclusions The inspectors identified that inadequate communication was the cause of the shif t supervisor not knowing what the approved contingency plan was when the plant was in a higher risk evolution. This higher risk evolution existed because primary and secondary containment were not established. Also, the inspectors identified that the licensee had not formally identified the conditions at which approved contingency plans for two higher risk evolutions (loss of vessel temperature control and loss of decay heat removal capability) would be implemented. As a result of the inspectors' observations, the contingency plans were briefed to the shift supervisor and revised to identify the entry conditions.

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-3-03 Operations Procedures and Documentation O3.1 Review of Standina/Nicht Orders Inspection Scope (71707)

The inspectors reviewed the active standing orders to determine whether they provided the appropriate document to direct operator action b. Observations and Findinas On October 1,1998, the inspectors reviewed the active standing orders to determine the scope of guidance provided to operators. Operations Instruction 4," Standing and Night Orders," dated February 23,1998, stated that standing orders were management information and instructions that may require operator action and have short term applicability which required dissemination. Standing orders contained special plant operations, administrative directions, or special data collection. The inspectors noted that several of the standing orders directed operators to perform certain functions in response to certain plant conditions. The inspectors questioned the propriety of using standing orders to direct operational activities in place of incorporating the necessary I

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information into a new or existing procedure. Licensee management stated that using standing orders was acceptable because in each instance the standing orders were more conservative or restrictive than existing procedure Observations regarding specific standing orders are discussed below: j Standina Order 98 010 This standing order was issued January 25,1998, and was to remain in effect until the guidance was incorporated into a procedure or operations instruction. It stated, upon discovery of unisolable leakage or leakage from the criticalloops of the reactor equipment cooling system, to perform the following compensatory actions: (1) evaluate

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leakage per Procedures 6. MISC.501, "ECCS Leakage Walkdown," and 13.1, "ECCS Leakage Evaluation," to determine if leakage is from valve packing or pump seals and is confined to that type of leak; (2) calculate leakage in terms of gallons per day; (3) compare leakage and determine reactor equipment cooling surge tank level necessary to compensate for the leakage from attached graphs; and (4) establish and maintain reactor equipment cooling surge tank level determined in Step 3 until condition is correcte Procedure 6. MISC.501 provided instructions for identifying and quantifying leakage from the emergency core cooling system that could potentially affect postloss of coolant accident design basis calculations. The above guidance was not in the approved procedure. The standing order stated that maintaining the reactor cooling system inventory loss rate below 5.75 gallons per day assured that the reactor equipment cooling system would remain operable for the entire 30-day design basis accident loss of coolant accident duration. A graph attached to the standing order displayed the I

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l required reactor equipment m ? ag surge tank level as a function of reactor coolant !

system loss. The standing c 'er also stated that engineering was developing a formal l calculation for reactor equipiaent cooling surge tank level and allowable uncontrolled j inventory loss. This standing directed activities affecting plant operation that were in '

addition to, and different from, that provided in approved procedure l Standina Order 98-020

i This standing order was issued July 17,1998, and was to remain in effect until the j guidance was incorporated into a procedure. This standing order directed operators to maintain turbine equipment cooling pump discharge pressure and turbine equipment temperature in a band different from that contained in Procedure 2.2.76, " Turbine I l

Equipment Cooling Water System." The turbine equipment cooling system provided i

cooling to control room Air Conditioner AC-C-1 A, the reactor feed pump lube oil coolers, and the steam tunnel coolers. This standing order changed the operating characteristics of the turbine equipment cooling system without evaluating its effect on the components cooled by the turbine equipment cooling system. This standing order directed plant operation that was different from the guidance provided in approved )

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Standina Order 98-025 This standing order was issued September 6,1998, and was to remain in effect until l l incorporated into the procedure. This standing order directed operators to review the j l handwritten revisions to Design Criteria Document (DCD)-13, Residual Heat Removal l System. Step 5.51 of DCD 13 originally stated that the cooling system in the residual heat removal system rooms was necessary to maintain normal operating temperatures

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during standby, test, and operation of the residual heat removal system. However,

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failure of the heating, ventilation, and air-conditioning system would not cause the residual heat removal system room temperature to exceed operating limits when floor plugs are removed. The step was revised to state that the cooling system in the residual heat removal system rooms is necessary to maintain normal operating temperatures during standby, test, and operation of the residual heat removal syste However, failure of the heating, ventilation, and air-conditioning system would not cause the residual heat removal system room temperature to exceed operating limits when floor plugs are removed for single pump operation within a heat removal system roo The DCD required that room cooling must be established within one hour if two-pump operation occurs. The standing order, through implementation of the DCD changes, required operators to operate the plant in a manner that was not addressed in approved procedure Standina Order 98-028 This standing order was issued on September 16,1998, and was to remain in effect

until completion of an engineering analysis and procedure change. This standing order i directed operators to remove loads from reactor equipment cooling per Step 15.1 of Procedure 2.2.65," Reactor Equipment Cooling Operations," prior to reaching 91 F and i

evaluate whether to remove the reactor water cleanup system from service. When l

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-5-temperature indicates 91 F, operators perform actions associated with Step 15.2 of Procedure 2.2.65.1, " REC Operations." The approved procedure required the actions in Step 15.1 to be performed when temperature was less than 95 F and the actions in Steps 15.2 were to be performed when temperature was greater than 95*F. No evaluation of the temperature change was performed. The standing order directed plant operation in a manner different from that provided in approved procedure Standino Order 98-029 This standing order was issued on September 21,1998, and was to remain in effect until procedures were revised. This standing order directed operators to use only one loop in suppression pool cooling, two pumps if required, during planned testing that adds heat to the suppression pool, as an interim conservative measure, unless average suppression pool temperature reaches 100*F. It further directed operators to declare inoperable the residual heat removal loop placed in suppression pool cooling. If

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average suppression pool temperature reaches 100 F, it directed operators to place both loops suppression pool cooling, provided they are both declared inoperable and Technical Specification 3.0.3 limiting condition for operation is entered immediatel This directed plant operation in a manner not covered by procedur The inspectors noted that Technical Specification 5.4.1 requires development and j implementation of procedures for operation of safety-related systems, such as the ,

systems mentioned in the standing orders, discussed above. Failure to incorporate the !

information in the standing orders into procedures is a violation (50-298/98007-01).

As corrective action for this violation, the licensee initiated a standing order screening I criteria. Its purpose was to evaluate the direction provided in standing orders to determine if they provided guidance that met the definition of an intent change, if they did, then a 10 CFR 50.59 screening evaluation would be required prior to implementing the standing orde Conclusions The licensee used standing orders as procedures to direct operational activities. Some standing orders contained direction that was different from that in approved procedure Although the standing orders were being used as procedures, they had not been processed in accordance with administrative requirements regarding procedure changes and generations. This precluded important steps or information contained in the standing order, but not in the referenced procedures, from being included in plant procedure ]

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03.2 Inadeauate Control of Reactor Water Level Durina the Removal of the Reactor Vessel Head Insoection Scoce (71707)

The inspectors followed the licensee's investigation into an indication of a 60-inch reactor water level drop, during remova! of the reactor head vent. Discussions were j held with operations and engineering personne i l Observations and Findinas

On October 4,1998, cperators were raising reactor water level to 180 inches for the !

removal of the reactor vessel head. At 170 inches, operators noted that reactor water )

level started dropping at 6 inches / minute. The operators immediately placed all reactor building sump control switches to off to determine where the water was going. There was no indication of leakage (sump levels remained constant). Reactor water level stabilized at 112 inche l Concurrent with raising reactor water level, preparations were being performed to lift the reactor vessel head. As the reactor head vent was being removed, workers heard air escaping. Historical plots showed reactor pressure was rising just before level started to drop and when the reactor vessel was completely vented, level stabilized at 112 inche The plot showed that indicated reactor water level peaked (169.8 inches) at the same time reactor pressure peaked (1.789 psig). This indicated that the reactor water level was not being accurately monitored. Based on water levelindications, operators thought water level was at 170 inches when it actually was at 112 inche Reactor water level was to be at 180 inches prior to lifting the reactor vessel head to help minimize dose to the disassembly crews. The water level being below 180 inches was significant, because the level was at 180 inches when the reactor vessel head was removed. The inspectors by talking with the radiation protection technician, confirmed that the dose limits of the crew removing the reactor vessel head vent were not exceede Prior to raising reactor water level, reactor pressure was -0.745 psig and pressure peaked at 1.789 psig. Operators did not question or evaluate the effects the increase in reactor pressure would have on reactor water level. Also, no one estimated when the reactor water level would be at 180 inches using the fill up rate to ensure level instrumentation was working properl The licensee's evaluation for this issue was still ongoing and due January 28,199 Preliminarily, the licensee stated the cause was possibly raising water level faster than the capacity of the reactor head vents or the reactor head vents were not actually opened as indicated. As interim corrective actions, the licensee revised Procedure 2.1.20, " Reactor Pressure Vessel Refueling Preparations," by adding steps to open additional vont valves and watch reactor pressure while increasing water leve Also, a caution step was added to warn operators that, if the fill rate exceeds the capacity of the vents, indicated water level would be higher than actual water leve .

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7 Conclusions Indicated reactor water level dropped 58 inches when the reactor vessel head vent was removed. During this event, operators failed to question or evaluate the change in reactor pressure on reactor water level, nor did they calculate the time to reach 180 inches while increasing reactor water level. No increased exposure to workers resulted from the inaccurate water levelindication. The inspectors reviewed the licensee's interim corrective actions and found them appropriate to prevent recurrenc Operator Knowledge and Performance 04.1 Inocerable Postaccident Eouloment Inspection Scope (71707)

The ;.1spectors followed up to determine why the limiting condition for operation was not entered when Technical Specifications-required equipment was made inoperabl Observations and Findinas On October 2,1998, operators implemented Clearance Order 98001193 to allow performance of Procedure 6.PC.522 " Standby Nitrogen Injection and PC Purge and Vent System Local Leak Rate Test." While the test was being performed, operations personnel walked down the contrc! boards and noticed anomalies in chart recorders for PC-PR-2A (Torus Pressure) and PC-LR-1 A (Torus Level). Both recorders were affected by the localleak rate test pressure. These anomalies resulted in both instruments being declared inoperable. A 30-day limiting condition for operation, Technical Specification 3.3.1.1.a. was entered.

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clearance order rendered the postaccident monitoring pressure and level transmitters inoperable. When the clearance was developed and hung, operators did not recognize

that it made the instruments inoperable. As a result, they did not enter the applicable l limiting condition for operation.

l l The licensee initiated a problem identification report and planned to change l Procedure 6.PC.522 to indicate, that during its performance, the two transmitters would

be rendered inoperable. The intended procedure change would remind operators to

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enter the limiting condition for operation. The operators involved in constructing and hanging the clearance were also counseled. Failing to enter the applicable limiting condition for operation when the instruments were rendered inoperable is a violatio This nonrepetitive, licensee-identified and corrected violation is being treated as a noncited violation, consistent with Section Vll.B.1 of the NRC Enforcement Policy (50-298/98007-02).

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8- Conclusions Operations personnel failed to identify during the development and implementation of a l clearance order that Technical Specifications required postaccident instrumentation was rendered inoperable. As a result, the limiting condition for operation for the i instrumentation, Technical Specification 3.3.1.1.a was not entered. Control room i operators noted that the equipment was inoperable hours after the clearance order was hung during a routine control board walkdown. This is a noncited violation of Technical Specification 5. O4.2 Valid Scram Sional Due to Human Error Insoection Scoce (71750)

The inspectors reviewed the licensee's actions associated with two scram signals received during the refueling outage. Discussions were held with operators, engineers, maintenance, and licensing personne Observations and Findinas On October 6,1998, a full reactor scram occurred due to a faulty test lead installed for intermediate range monitor troubleshooting. Upon resetting the scram signal, a licensed operator failed to bypass the high level scram signal for the scram discharge volume, resulting in a valid scra During the crew brief at the beginning of the shift, the operators discussed the need to maintain reactor water level within a relatively small band near the reactor vessel flange ,

to keep the steam dryer submerged and minimize dose to the disassembly crews. They l also discussed an expected half scram condition due to planned troubleshooting of the l

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intermediate range monitor. Operators were instructed that, in the event of a scram, to diagnose and reset the scram in a timely manner to control reactor water leve l l

When the initial scram occurred, an operator determined the cause of the scram and then proceeded to reset the scram without looking at the appropriate procedu, Procedure 4.5," Reactor Protection / Alternate Rod insertion Systems," Revision 20, Step 8.3.2, instructed the operators to bypass the high scram discharge volume during resetting of the scram signal. A second licensed operator performing peer checks recognized that the scram discharge volume high level trip had not been bypassed and reasoned that it was not a problem. Within 20 seconds of resetting the initial scram, a l second scram occurred on high level in the scram discharge volum The licensee determined the root cause to be inadequate planning for the potential operational occurrence, because no actions were taken during the preshift brief nor during the subsequent shif t to review procedures and actions. Also, the licensee identified contributing factors of time pressure, peer checker not vocalizing his concern, lack of familiarity with appropriate procedures, and the lack of simulator training on associated actions for scrams while shut dow l Y

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, - . - - - . l 9-l i The licensee's immediate corrective actions consisted of holding tailgate sessions with l the crews. Planned corrective actions were to: (1) share the lessons learned as a case l study in training; (2) revise the peer-checking expectations; (3) revise operations l instructions to require a brief for tasks that are time critical; and (4) evaluate additional methods for responding to and controlling time pressure and provide appropriate i training. The inspectors concluded that the licensee's planned corrective actions adequately addressed the root cause and the contributing cause The failure to bypass the high scram discharge level trip as directed by Procedure 4.5 is a violation of Technical Specification 5.4.1," Procedures." This nonrepetitive, licensee-identified and corrected violation is being treated as a noncited violation consistent with ;

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Section Vll.B.1 of the NRC Enforcement Policy (50-298/98007-03). l l

' Conclusion During a reset of a reactor scram signal, a licensed operator failed to follow station i operating procedures to bypass the scram discharge volume high level trip. This I l resulted in a second reactor scram. A second operator acting as a peer check noted i that the operator failed to bypass the scram discharge volume high level trip, but

! reasoned that it was not a problem and did not question that operator. Failure of the peer checker to vocalize his concern was identified as a contributing cause of the

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08 Miscellaneous Operations issues

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0 (Closed) Licensee Event Report 50-298/98-008: Technical Specifications Violation Due

to Missed Testing of Reactor Building Suppression Chamber Vacuum Breakers. The l licensee determined that Check Valves PC CV 13CV and PC-CV-14CV of the reactor

building suppression chamber vacuum breakers were not tested for proper operation l every 3 months as required by Technical Specifications.

l l Until May 1988, the licensee tested the entire vacuum breaker assembly on a quarterly l basis, in 1988, a relief request was granted for the two check valves due to their hazardous location. Based on the relief request, Procedure 6.2.5.1, " Suppression Chamber Reactor Building Vacuum Breaker Functional Test," was revised to allow

testing of the check valves every 2 years. During the revision, the licensee incorrectly j determined that this satisfied the Technical Specifications requirements.

l l As a corrective action, the licensee performed the Technical Specifications required tes The valves performed satisfactorily. Failing to perform the test in accordance with the Technical Specifications is a violation. This nonrepetitive, licensee-identified and corrected violation is being treated as a noncited violation, consistent with Section Vll.B.1 of the NRC Enforcement Policy (50-298/98007-04).

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! 08.2 (Closed) Licensee Event Reoort 98-009: Operator error results in unexpected full scram

! on high scram discharge volume level. This event is discussed in Section 04.3 of thir j report. No new issues were identified; therefore, this item is close !

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l-10-II. Maintenance M1 Conduct s.f Maintenance l M1.1 General Comments l

! , Inspection Scoce (62707)

The inspectors reviewed work packages and held discussions with maintenance craft, operations, and managemen Observations and Findinas I

The inspectors observed all or portions of the following activities: l Maintenance Work Request 97-2797 Diesel Generator 2 Mechanical inspection l l Maintenance Work Request 98-2933 Inspect and Clean Diesel Generator 2 Lube Oil Heat Exchanger j Maintenance Work Request 98-2852 Remove, Rebuild, and Install Valve AR-AO-12AV Maintenance Work Request 98-0943 Replacement of Intermediate Range 1 Monitor Detector F Maintenance Work Request 98 2497 Service Water Piping inspection Maintenance Work Request 98-0129 Residual Heat Removal Heat Exchanger B Inspection / Cleaning Maintenance Work Request 98-2782 Diesel Generator 2 Air Inlet Intercooler Inspection / Cleaning Maintenance Work Request 98 2756 Diesel Generator 2 Output Breaker Mode Selector Switch Modification Maintenance Work Request 98-1291 Diesel Generator 2 Output Transformer Replacement The inspectors noted that the activities were well controlled and work instructions were performed as written. The inspectors also noted that material condition of equipment

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. l-11 - . Conclusiong Performance of maintenance activities were well controlled and performed in a step-by-step manner. Plant material condition was also goo M2 Maintenance and Material Condition of Facilities and Equipment M2.1 Service Water System Underaround Pipina Internal Protective Coatina Failure Insoection Scoce (71707)

Inspectors monitored the licensee *s troubleshooting activities and operability evaluations when degradation of protective coating used inside of underground service water piping deposited pieces of the protective coating in the Diesel Generator 2 lube oil heat exchange Observations and Findinas Problems with coal tar flaking in the low pressure service water system were first identified and evaluated at the Cooper Nuclear Station in 1973. The inspectors reviewed a report issued June 1,1973, titled, " Report on Cooper Nuclear Station Tar Flaking in Piping System." This 1973 report attributed coal tar flaking to failure of the coating bond to the bare metalinterior surface of the piping. As corrective actions, strainers were installed in the service water system as follows: (1) four strainers in the suction lines for the four residual heat removal system service water booster pumps, (2) one strainer in the service water cupply line for Diesel Generator 1, and (3) two strainers in the nonsafety service water lines to the emergency supply to control room air-conditioning and control building basement ventilation. No strainer was installed in the service water supply to Diesel Generator 2, contrary to what was recommended by the report, and no documentation could be found that identified why the strainer was not installed. Problem Identification Report 3 40160 was issued to initiate actions to install a straine On October 7,1998, a visual inspection of the service water inlet waterbox side of Diesel Generator 2 lube oil heat exchanger identified pieces of coal tar. These pieces of coal tar were found on the bottom of the inlet side of the heat exchanger waterbox in 30 tubes (10 percent of the total tubes) of the heat exchanger. The coal tar did not restrict flow. The pieces of coal tar were irregular in shape and ranged from very small to approximately 3/4-inch across, with a thickness of approximately 1/16 to 3/32 inc The licensee documented this observation of foreign materialin Problem Identification Report 3-2017 On October 9,1998, a visual inspection of Diesel Generator 2 turbo charger intercoolers (heat exchangers for the lef t and right banks) found small pieces of coal tar lying on the bottom of the inlet waterbox. No coal tar was found lodged in the tubes of either intercooler. The licensee documented this observation of foreign materialin Problem identification Report 3-0016 ______ _ _ _ N

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12-On October 16,1998, the licensee inspected the internal surfaces of approximately 230 feet of one of the two 24 inch diameter service water lines using a video camer The inspectors reviewed the inspection video tapes and noted it was difficult to evaluate the as found condition of the coal tar coating. Video tapes of inspection observations were provided to engineering, the pipe coating manufacturer, and an engineering consultant for revie Other plant inspections identified small coal tar flakes in the inlet and outlet of Residual ;

Heat Removal Heat Exchanger B and Diesel Generator 1 turbo intercooler. The 1 licensee initiated Problem Identification Report 3-50956 to document these findings.

l Based on procedure instructions for strainer blowdown or flushing and inspection history l for the strainers, the inspectors identified the following:

l . There was no documented scheduled inspection or monitoring periods for the

! seven strainers installed to collect coal tar flakes or other contaminants.

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. The four residual heat removal service water booster pump strainers were last l opened and inspected in 1985. Records did not identify why the strainers were opened in 1985, or if they were inspected for coal ta l

. High differential pressure of 10 psid across any of the four residual heat removal j l service water booster pump strainers initiated an annunciator alarm condition in i the control room and required the strainers to be blown down. There were no l records of how many times these alarms had come in or the frequency that the

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strainers were blown down/ flushe . Records did not identify whether the Diesel Generator 1 service water supply strainer inspected this refueling outage or the other two nonsafety coal tar strainers had been opened and inspected since installatio . High differential pressure of 3.5 psid across the Diesel Generator 1 strainer initiated a trouble indication light at the local Diesel Generator 1 control panel, but did not initiate an annunciator alarm condition. There were no records readily available to determine if this light had ever been initiated and licensee corrective actions implemente The inspectors reviewed the operability determination and noted that the licensee had provided the following summary information on the loose coating material observed:

. Based on internalinspection of the 24 inch diameter Division 2 service water l line, and the examinations of heat exchangers, the licensee found only a limited

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amount of coating materialin the heat exchangers. Plant personnel considered material found in the Diesel Generator 2 lube oil cooler and Diesel Generator 2 intercooler heat exchangers similar to the amounts typically found during routine inspections.

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The amount of coating material observed in the heat exchangers posed only a very limited amount of flow blockag . The major heat exchangers (such as one of the residual heat removal heat exchangers) are normally disassembled and cleaned or backflushed (such as the reactor equipment cooling heat exchanger) at regular intervals, removing materials which build u . The Diesel Generator 2 heat exchangers had all been cleaned during the current refueling outag .

The Diesel Generator 2 lube oil heat exchanger was inspected and found clean a second time after the initial cleaning during this current outage. The second inspection was performed followirg a 6 hour6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> Diesel Generator 2 run performed with Division 1 service wate .

Visualinspections of the Residual Heat Removal Service Water Booster Pump B and D strainers and the Diesel Generator 1 strainer found no coal ta .

Discussions with the coating vendor indicated the coating had reached its expected end of life (15 to 20 years). Rapid or catastrophic failure of the coating, including significant de lamination, was not expected. Rather, the most likely failure mode expected at this time was flow undercutting the coating, causing it to flake off in small piece .

Regular inspections of the above ground service water piping are conducted for the Erosion / Corrosion Program. The service water system is currently classified in Category (a)(1) under the Maintenance Rule Program. The above ground service water piping has no internal coating. Since much of the underground piping was protected for at least part of its life, the corrosion in this area would be less than that piping which had never been protecte Based on these facts, the licensee concluded that the service water system was operable and capable of supporting the residual heat removal, reactor equipment cooling, diesel generators, and related system On October 21,1998, Problem Identification Report 3-50402 was issued to document that, in 1973, there were areas of the fire protection system piping scheduled to have an internal coal tar coating installed, and that no recent inspections had been performed in those areas. The inspectors reviewed the licensee operability determination and did not identify any issues. Based on the information reviewed by the inspectors, the current rate of degradation of the underground service water piping internal coating was low and was not currently challenging the operability of the safety-related equipment. The licensee identified that additional monitoring actions / enhancements would be implemented to ensure that operability of the affected equipment would be maintaine As of November 4,1998, the licensee identified that there was not a formal program in place to monitor the degradation of the internal coating systems installed in undergrou,,d

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-14-piping systems (such as service water and fire protection). The extent of this condition and the corrective actions are still bein0 evaluated by the licensee. Therefore, an inspection followup item will be opened to review the licensee's corrective actions (50-298/98007-05). Conclusion in 1973, the licensee identified degradation of the internal coating installed in ,

underground piping, such as service water and fire protection systems, and did not implement a program to monitor this degraded condition. The material captured in the strainers which were installed as corrective actions was not being monitored. The licensee's initial troubleshooting activities were performed in an adequate and controlled i manner, and the service water system and fire protection system operability determinations were adequat I M7 Quality Assurance in Maintenance Activities M7.1 Quality Control Deficiencies Insoection Scoco (62707)  !

t The inspectors followed up on several instances in which quality control hold points or )

l quality control witness steps were skipped during maintenance.

! Observations and Findinas

! Missed Quality Control Hold Steo on inspection of the Steam Line Pluas I

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! On October 6,1998, maintenance personnel were performing Maintenance l l

Procedure 7.4.27, " Main Steam Line Plug installation," to install the main steam line '

plugs inside the reactor vessel. Following installation of the plugs, licensee personnel l reviewed the procedure and noted that a quality control hold point had not been completed. This hold point required quality control personnel to inspect the inflatable seal, verify its integrity, and check for any indication of a potential failure. Maintenance personnel had skipped this step in the procedur As a corrective action, the licensee removed the inflatable seals, performed the quality controlinspection, and verified the integrity of the seals. Additionally, the licensee initiated an all hands standdown to discuss the importance of following procedures and to stress attention to detail. Maintenance personnelinvolved were also counsele Failure to obtain Quality Control Witness of BglLToraue

On October 12,1998, during the reassembly of Check Valve HPCI CV 29CV, a contract mechanic performed a step in the maintenance procedure to torque the bolts on the end l

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, caps / stuffing box of the valve. The mechanic then intended to sign the procedure to I indicate completion of that step. The mechanic then realized that the step required quality control to witness the bolts being torque As corrective action, the work package was modified to relax the torque on each of the bolts and the bolts were retorqued to the specified valve with quality control present to witness the torque. A standdown was also heid with contract personnel to discuss i expectations regarding: quality control steps, qudity of work verses schedule, control of I

work, procedural adherence, human performance, and self-checking, Missed Quality Control Hold Step on Final Cleanliness inspection On October 12,1998, a contract mechanic and a quality control inspector entered the

, steam tunnel to begin reassembling Check Valve HPCI-CV-29CV. Since it was near to l

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shift turnover, the mechanic and quality control inspector agreed that vaks assembly could continue and that the oncoming quality control inspector could perform the final quality control foreign material exclusion inspection. Turnover between shifts was inadequate. Oncoming personnel did not understand the agreement made by offgoing personnel. Also, oncoming personnel did not stop the job even though they were not sure of the status of the inspection. As a result, a foreign material exclusion quality control hold point was not completed. As corrective action, the licensee ensured the foreign material exclusion inspection was performed.

l Failing to perform quality control requirements is a violation. This nonrepetitive,

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licensee-identified and corrected violation is being treated as a noncited violation, l

consistent with Section Vll.B.1 of the NRC Enforcement Policy (50-298/98007-06).

l Due to the number of missed quality control requirements, quality assurance audited several completed work packages to verify they were satisfactorily completed. During the audit, no other discrepancies were note Conclusions During the outage, the licensee identified instances in which quality control hold points and quality control witness steps were not performed by maintenance personnel. No single cause was identified as the source of the quality control deficiencies. In each instance, af ter the licensee realized that the required quality control functions were not performed, the licensee took actions to ensure the quality control functions were performe M8 Miscellaneous Maintenance issues (92902)

M8.1 (Closed) Violation 50-298/97007-05: Failure to include proper test criteria in procedures. This violation contained two examples of test procedures that did not provide the appropriate test requirements. The first example, Procedure 6.PC.308,

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"Drywell Pressure Suppression Chamber Vacuum Breaker Calibration and Functional Test," did not account for a differential pressure across the torus-to-drywell vacuum i

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breakers during lift-force testing. The second example, ResDal Heat Removal '

Valve RHR MOV MO348, was not tested using a new stroke ume limi The inspectors verified that the licensee completed the corrective actions described in

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the licensee's response letter, dated October 9,1997. The inspectors noted that, as 1 I

part of the corrective actions, the licensee revised Procedure 6.PC.308 to require that l 6 of the 12 torus-to-drywell vacuum breakers be opened. These vacuum breakers were j being opened to equalize the pressure between the drywell and the torus prior to the

! performance of the lift test. The licensee performed Procedure 6.PC.308 on August 2, 1997, in which the six vacuum breakers were cycled prior to performing the as-found lif t test. Cycling the six vacuum breakers preconditioned them; therefore, the as-found test l

results were not valid. The licensee wrote Problem identification Report 3-00058 to l document the concern and evaluate whether cycling the six vacuum breakers prior to

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performing as-found testing was preconditioning.

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l The licensee agreed that opening any of the vacuum breakers prior to performing the

! test could remove any pre-existing condition that may cause the vacuum breakers to fail the acceptance criteria. As corrective actions the licensee revised the procedure. The steps to cycle the six vacuum breakers were removed and steps were added to ensure that the torus and drywell pressure were equal using one of two method On November 3,1998, the licensee performed the revised procedure and all 12 vacuum l

breakers met the acceptance criteria. The failure to implement effective corrective ,

actions for the previous inadequate torus to-drywell vacuum breaker test criteria is a l l

violation of 10 CFR Part 50, Appendix B, Criterion XVI (50-298/98007-07).

No further problems were identified and Violation 50-298/97007-05 is close M8.2 [ Closed) Unresolved item 50-298/97018-02: Corrective Actions and Root Cause Assessment of 4160 V breakers. The licensee had established an informal overhaul program for the safety-related 4160 V circuit breakers in 1987. From 1989 to 1994, the licensee sont 18 of 24 safety-related 4160 V circuit breakers to be overhauled. In ,

l August 1994, the overhaul process was canceled because of an extended outage, a l redirection of priorities, and the fact that the process was not formalized.

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The licensee implemented a plan to overhaul the remaining safety-related 4160 V circuit i

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breakers once they realized that the overhaul program was canceled. The inspectors noted that no discrepancies were identified during the overhaul that would have i rendered the circuit breakers incapable of performing their intended safety function ,

i The inspectors also observed that the licensee had developed a preventive l l maintenance task to overhaul the 4160 V circuit breakers on a periodic basi l Additionally, the inspectors noted that the licensee had developed a program to overhaul the nonsafety-related 4160 V circuit breakers.

. The inspectors found that, while the lack of a formalized overhaul program did not result

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in the failure of safety-related 4160 V circuit breakers, the licensee's actions to formalize an overhaul process in the preventive maintenance program met expectations for implementing industry operating experience. Additionally, the inspectors found that, l

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because of testing performed on the circuit breakers that had not been overhauled, and

! the results of initialinspections during the subsequent overhaul of those breakers, the ,

l breakers could perform their intended safety-functions. Therefore, there was no l violation of regulatory requirements.

M8.3 (Closed) Inspection Followuo item 50-298/97018-03: Adequacy of Licensee's Maintenance for 480 V Circuit Breakers. Inspectors questioned the use of resistance measurements to demonstrate that the auxiliary contacts actuated before the end of travel of the breaker. Also, the inspectors questioned the extension of time between the performance of preventive maintenance inspections greater than the vendor's recommendation With respect to the verification of auxiliary contact closure, the inspectors discovered that the issue had not been addressed. Because of this finding, a licensing representative initiated Problem Identification Report 3-40290 to address why the issue had not been addressed. Although the issue had not been addressed, the inspectors did not identify any safety or regulatory concern associated with the followup ite Therefore, no additional information is required by the inspectors to close this ite The inspectors noted, during a review of the licensee's evaluation for extending the time between the performance of inspections for the DB-50 circuit breakers, that adequate justification was provided to perform the inspections at the frequency specified in the preventive maintenance program. The inspectors also noted that the established frequency (36 months) was supported by industry experience with respect to the performance of the DB-50 circuit breakers. The inspectors found the licensee's periodic inspection frequency to be adequate to assure that the circuit breakers could perform their intended safety function M8.4 (Closed) Inspection Followuo item 50-298/97013-03: Environmental Qualification of !

Low-Low Set System Pressure Switches. Inspectors questioned the adequacy of the evaluation to reclassify the low-low set pressure switches as nonessential for an environmentally qualified program. During this inspection, the inspectors reviewed the documents developed in support of the reclassification and interviewed plant personnel l knowledgeable of the environmental qualification program. The inspectors found that

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the pressure switches were not located in an area that would be subject to a harsh environment for an accident that the pressure switches would be required to mitigat Therefore, the inspectors concluded that the reclassification was acceptabl Ill. Enaineerina l

E Inadeauate Postmodification Testino on the Diesel Generator l

l Inspection Scope (37551 and 62707)

The inspectors reviewed licensee actions to address inadequacies identified in the postmodification testing requirements following a modification to the diesel generato )

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-18-b. Observations and Findinas During the current refueling outage, Modification 96150 was performed on Diesel Generator 2 to eliminate the need to operate the mode selector switch in the remote position during monthly diesel generator testing. The mode selector switch was to remain in the automatic position allowing automatic closure of the output breaker if a loss of coolant accident or a loss of offsite power occurred during monthly testin !

Maintenance Work Request 98 2756 contained the instructions to implement the I modification and specified the postmodification testing requirement I

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On October 16,1998, following the maintenance, operations personnel attempted to perform a postmodification test. However, operators could not get the output breaker to close while the breaker was in the test position. This prevented the completion of the postmodification test. Troubleshooting determined that a relay contact in the trip circuit, normally closed when the dieselis shut down, prevented the closure of the output breaker, as designed. This was caused by a closed contact for Relay K1. This relay ,

was associated with the diesel generator exciter. This contact is normally closed when i the dieselis shut down and only opens when the diesel engine is operating. The test I instructions provided in the modification package did not recognize that the contact was closed. This caused the output breaker of the diesel generator to trip open when breaker closure was attempted. To correct this problem, steps were added to the i postmodification test work instruction section to lif t a terminal wire on the closed relay contact. This disabled the trip signal to the output breaker and allowed closure of the output breaker while in the test positio Additional reviews of the modification package by operations identified the following l concerns ,

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. No continuity or functional test of Contact 6 (annunciator alarm), l l

. No functional test to close the output breaker with Diesel Generator 2 in local l control, and

. When verifying that the Board C breaker control switch will not close the breaker while in local control, the sync switch should be o The licensee took appropriate actions to address each of these issue Problem Identification Report 3-20364 was written to address programmatic issues of how the faulty test instructions were created, reviewed, and subsequently issued to the field. This item will remain open to evaluate resolution of the programmatic issues (50- )

298/98007-08), i I

c. Conclusions Severalinadequacies were identified in the postmodification testing requirements '

following a modification to the diesel generator output breaker mode selector switc I l

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, 4 Specifically, the work instructions prepared by engineering did not identify that a contact on a relay in the exciter circuitry was closed which prevented the diesel generator output breaker mode selector switch from being successfully tested. Additionally, the package had to be revised to address other testing inadequacies identified by operations l personne :L E1.2 Diesel Generator Overoower Relav Modification j Inspection Scope (37551)

b The inspectors reviewed the circumstances surrounding the tripping of Crosstie Breaker 1GB dering surveillance test.n Observations and Findinas On October 20,1998, as part of the endurance run for Diesel Generator 2, operations personnel were attempting to run the diesel generato'r, loaded between 4200 kW and 4400 kW, for approximately 2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br /> as required 'oy Technical Specification 3.8. I Operations personnelincreased load to approximately 4300 kW. Sho.9 thereafter, l Crosstie Breaker 1GB opened. This breaker provides power to the nonessential Bus B l from the essential Bus G. When the crosstie breaker opened, all nonessentialloads

were shed from the essential bus. Operators were surprised that the crosstie breaker opened, and they initiated a problem identification repor During the subsequent evaluation, it was identified that earlier in the outage workers had

corrected a wiring error from Modification DC 87133 performed in 1988. On an l

overpower condition, the relay would trip and isolate the diesel generator to ensure it

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was not overloaded. Overload protection during emergency operation was not required since the plant design ensured that accident loads did not exceed the diesel capacit However, during surveillance testing, when the diesel generator was paralleled to offsite l

l power sources, the potential existed for the diesel to attempt to carry more than its rated loa The 1988 modification did not wire the relay sensing circuits correctly, the relay could not detect power being delivered by the diesel generator, and it did not function as i designed. The postmodification test instructions did not verify the circuit all the way l back to the sensing devices. As a result, the postmaintenance testing did not identity that the modification was incorrectly wired. Following work performed during this

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outage, the overpower relay was verified to open at approximately 4300 kW and trip

! Crosstie Breaker 1GB.

l The work package developed to correct the relay wiring did not ensure that all procedures affected by completion of the modification were reviewed as required. The modification design package did not fully examine the effect that the modification would have on Technical Specifications required surveillances. Also, the operations closeout review did not identify that the modification would prevent the performance of a required surveillance tes _ . . . _ _ _ . _ . . _ _ - _ _ _ _ _ _ . _ _ . _ . - _ . _ _ _ _ . _ ____._ _ __._._ _

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As corrective action, the licensee recalibrated the overpower relay to ensure it opened at 115 percent of rated loads, thus allowing completion of a Technical Specifications- ,

required activity. Drawings were revised and procedures were reviewed to determine if '

they would be affected by the modificatio Failing to ensure the adequacy of the modification package is a violation. This !

nonrepetitive, licensee-identified and corrected violation is being treated as a noncited

, violation, consistent with Section Vll.B.1 of the NRC Enforcement Policy (50-298/98007-l 09).

l Conclusions The development of a work package to correct a wiring error on the overpower relay of the diesel generator did not identify that surveillance procedures would be affected by l the work. Operations did not identify that the maintenance would prevent the performance of required surveillance testing during their closeout review of the paperwor E1.3 Adeauacy of Fuse Current Interruotino Capability Insoection Scoce (37551)

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The inspectors reviewed Problem identification Reports 2-2498,3-00211, and 3-50843 and Condition Reports 98-0038 and 98-0712. The inspectors also interviewed licensee engineers who were familiar with the problem documented in the reports.

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' Observations and Findinas While reviewing short circuit analysis calculations, a contract engineer noted that the current interrupting capability of fuses in the 125 Vdc and 250 Vdc systems was less than the ca'culated fault currents. The fuse interruption capacity is the maximum current that the fuse has the capability to interrupt. The worst case calculated fault ,

current was approximately 24,000 amperes and the fuses were rated for '

20,000 amperes. The fuses had been installed as part of Design Change 90181 that q

' replaced the circuit breakers for the 125 Vdc and 250 Vdc starter racks and distribution I panels with fused disconnects. The fuses had been specified on the basis of a teleconference with the fuse vendor. At that time, the vendor had told licensee engineers that the current interrupting capability of the fuses was 20,000 amperes direct

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current at 300 Vd In response to the realization that the newly calculated fault current exceeded the rated interruption capability of the fuses, design engineers prepared an operability i determination. During their review, operators questioned the initial draf t of the 1 j operability evaluation. The operations staff questioned the use of a teleconference j memorandum as a basis for the selection of the fuses and requested that engineering furnish documentation of the suitability of the fuses provided on the vendor's letterhea j . When the vendor provided documentation to the design engineers, the engineers noted that the fuse interrupting capability was only 10,000 amperes direct current at 300 Vde,

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-21-I much less than originally reported. With such a large difference between the calculated l fault current and the interrupting capability, the design engineers determined that the i subject fuses should be replace !

l The inspectors found that plant staff, that prepared, reviewed, and approved the list of

! replacement fuses as corrective action to this problem failed to verify that all the fuses on the list were the correct fuses. They also failed to verify, for the 250 Vdc swing battery charger, what the proper fuse should have been. The inspectors also found, I

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however, that the quality of the evaluations, in totality, was improved over past performance. During the installation of the replacement fuses, maintenance personnel discovered the discrepancies. As a result, the correct fuses were obtained and reinstalled in both the 125 Vdc and 250 Vdc swing battery charger The inspectors noted that, to lose a battery train, a short would have to occur at the precise location that would provide a current greater than the current-interrupting capability of the fuse. Such a short would be the single failure assumed in the accident

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analysis; therefore, the loss would affect only one train. The design of the plant, as I

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documented in the accident analysis, accounts for this single failure. The inspectors also noted that the results of testing performed for the licensee by an independent laboratory on the previously installed fuses indicated that they could actually interrupt !

25,500 amperes of direct current at 300 Vde, despite their rating of 10,000 amperes. As l l a result, the licensee concluded that the previously installed fuses had the ability to l provide short circuit protection, despite the information provided by the vendor.

l The failure to install properly rated fuses is a violation of 10 CFR 50, Appendix B,

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Criterion Ill. This nonrepetitive, licensee-identified and corrected violation is being I

! treated as a noncited violation, consistent with Section Vll.B.1 of the NRC Enforcement Policy (50-298/9800710). Conclusions The licensee identified that the current interrupting capability of fuses in the 125 Vdc and 250 Vdc systems were rated for 10,000 amperes while the calculated fault current was 24,000 amperes. The licensee first identified this in 1990, which incorrectly justified the use of the lower rated fuses, which was consistent with the poor engineering performance noted at that time. The recent efforts, which resulted in the identification of this past problem, suggested an improving performance. However, the problems associated with identifying the affected fuses suggested a need for additional attention to improve work products provided on short notice. Even though the licensee tested the fuse s ana demonstrated an interrupting capability of 25,500 amperes, the fuses were on'y rated for 10,000 amperes. This was a noncited violation of 10 CFR Part 50, Appendix B, Criterion Il . . . - - - _ ___- - ~ . _ . - - - - - _ - - _ _ _ . - - . - - - . -

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22-l E Failure of RPS Channel A2 to Actuate on Valid Sianal Inspection Scoce (37551 and 62707)

During the review of this inadvertent RPS signal, the licensee discovered that actuation of the RPS Channel A2 north and south side scram discharge isolation volume high I level trip failed to occur. The inspectors reviewed the licensee's actions.

l- Observations and Findinos Following a review of the scram discussed in Section 04.2, the licensee identified on l

October 11,1998, that the RPS Channel A2 north and south side scram discharge '

i isolation volume high level trip did not actuate as it should have on a valid high level.

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The licensee initiated Problem identification Report 3-20273 on this failure of the RPS to

- actuate, with engineering and operations departments leading the review. The investigation found that improper installation of the power supply on Octot'er 2,1998, permitted power to be available to the annunciators and power indication lights, but not to the level transmitters. As a result the actuation did not occur. The licensee reinstalled the power supply correctly and verified that the Channel A2 scram discharge isolation volume signal did actuate.

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The inspectors concluded that technicians installed the power supply incorrectly due to a l lack of familiarity with installation, the uniqueness of the power supply, and the lack of human factoring to aid in ensuring correct installatio The postmaintenance test for the October 2,1998, power supply replacement checked voltages on the annunciators and power supply, but did not test the entire trip system since the licensee considered the RPS fail-safe. The licensee concluded that the postmaintenance test was inadequate and proposed to modify the installation procedure to assure correct power supplies installation. In addition the licensee intended to improve the postmaintenance test to verify that it verifies operabilit The failure to have an adequate postmaintenance test is a violation of 10 CFR Part 50, l Appendix B, Criterion XI. The inspectors reviewed the licensee's proposed corrective actions and found them to be appropriate and adequate. This licensee-identified and corrected, nonrepetitive violation is being treated as a noncited violation, consistent with Section Vll. 8.1 of the NRC Enforcement Policy (50 298/98007-11). Conclusions The licensee performed an inadequate postmaintenance test following the replacement of the power supply that supplied power to the scram discharge instrument volume

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Channel A2 level transmitter. This resulted in the failure of the Channel A2 t.rm j discharge volume high level trip to fail on a valid RPS actuation. The licensee corrected the condition and initiated a problem identification report to address the inadequate test.

l E8 Miscellaneous Engineering issues l \

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23-E8.1 (Closed) Unresolved Item 50 298/97018 0_4: Adequacy of 125 Vdc Load and Voltage Study. The inspectors identified four problem areas related to the 125 Vdc load profile ,

and battery charger sizing. These areas were: (1) nonconservatisms that could result j in the battery being incapable of performing its design function; (2) surveillance ,

procedures without acceptance criteria to demonstrate the capability of the battery to l perform its design function; (3) a failure to update the battery charger sizing calculation when the input calculation had been revised; and (4) a failure to include verification of breakers to function under reduced voltage With respect to the first area, the inspectors noted that the running current used in Calculation NEDC 87-131D, "125 Vdc Battery Load and Voltage Calculation,"

Revision 6, fer motor operated Valve HPCl MO-16, was supported by plant data. The design engincers re-evaluated the value to be used in the calculation and concluded it wo'2ld be mott conservative if the locked rotor current was used. The inspectors noted that the results of the calculation using the increased value indicated that the battery would continue to perform its design functio l Also associated with this issue was a nonconservatism introduced by errors in the l determination of the expected current values for two time intervals. The increase in the current values was also applied to the load profile calculation. The results indicated that the battery was operabl The inspectors found that, while there had been nonconservatisms in the load profile calculation, the battery was always operable. The inspectors did not identify any ;

violation of regulatory requirements for this are ;

With respect to the second area, the inspectors noted that the appropriate acceptance criteria were omitted from Procedures 6.EE.603, "125V Battery Service Test,"

Revision 2, and 6.EE.605, "250V Battery Service Test," Revision 2. The inspectors verified that both procedures had been revised to include the appropriate acceptance criteri The inspectors noted that the licensee engineers demonstrated that the batteries'

performance during the service tests was acceptable when the acceptance criteria were applied. As such, the inspectors determined that the batteries were operable. The inspectors found that, while the procedures did not include the appropriate acceptance criteria, the significance of the omission was very minor. As such, no violation occurre With respect to the third area, the inspectors identified that the battery charger calculation had not been revised, nor had an engineering judgement been developed to support the revised battery load profile. The inspectors did note that design engineering personnel were in the process of revising the battery charger sizing calculation and were scheduled to issue the revision by November 20,199 While the results of the revised sizing calculation were preliminary, the inspectors found that the battery chargers were adequately sized to perform their intended safety function. Although neither a revision nor an engineering judgement was issued after the

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1 load profile was revised, the failure to do so did not result in an inadequate calculation or

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incorrectly sized battery chargers. Therefore, the failure to follow Procedure 3.4.7,

' Design Calculation," Revision 13, had no safety significanc With respect to the fourth area, the inspectors noted that, as documented in NRC t

inspection Report 50-298/97-18, the licensee had demonstrated in 1987 and 1997 that the 4160 V breakers were capable of operating at reduced battery voltage. The

inspectors found tNI the testing of the breakers at a voltage higher than the minimum voltage was acceptable. Therefore, no violation of regulatory requirements existed.

f E (Closed) Licensee Event Report 50-298/97-014: Station Modification Creates Potential Inability to Mitigate Accident Consequences. This licensee event report was issued because of questions raised during an NRC architect / engineering inspection. The issue was identified as Unresolved item 50-298/9720123 and will be tracked under this

. unresolved ite IV. Plant Support R1 Radiological Protection and Chemistry Controls R Contamination Event on Refuelino Floor Resultino in Untakes of Radioactive Material by Four Individuals Insoection Scope (71750)

The inspectors reviewed the circumstances surrounding the contamination of the refueling floor and resulting uptake of radioactive material by four worker Observations and Findinos On October 3,1998, during the removal of the drywell head bolts with air tools, portions of the reactor cavity floor were inadvertently contaminated. The contamination was due to the exhaust air from air tools being used to support the work. Tool exhaust air was discharging into the outer bellows area of the reactor cavity. The bellows area contained contamination levels approaching 15,000,000 dpm/100cm2 Four individuals working in the area received uptakes of radioactive material. The assigned committed effective dose equivalent was from 2 to 6 mrem. Also, portions of the refueling floor were contaminated. The inspectors followed up and determined that the radiation work permit (RWP 1998-1090) required that highly contaminated surfaces (>50,000 dpm/100cm2) be kept wet to minimize airborne activity. The radiation protection technician supporting the job had allowed the bellows area to dry ou Based on the potential significance, the licensee performed a root cause analysis to ensure all deficiencies were identified and correcte .

The result of the root cause analysis were documented in Significant Condition Report 98-0611. The root cause analysis concluded that the lead refuel radiation

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-25-protection technician was performing multiple tasks outside the expectations for the outage position. Several other barriers also broke down. Some of these barriers included:

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The directions in the radiation work permit were not specifi .

In the prejob planning leading up to the refueling work, the lead radiation protection technician did not assist in developing the radiological job pla .

There was lack of radiation protection supervision and oversight of refuel floor activities leading up to the even .

The radiological job plan and radiation work permit were developed just prior to the jo Some of the immediate and short-term corrective actions included wetting down the area, cbtaining ali samples, initiating a problem identification report, counseling the refueling floor radiation protection technician, clarifying the guidance in the radiation work permit, and reviewing other work permits to verify the directions were specifi Failing to follow the requirements of the radiation work permit is a violation of the Technical Specification 5.4.1 requirement to implement procedures for radiation i protection. This nonrepetitive, licensee-identified and corrected violation is being treated I as a noncited violation, consistent with Section Vll.B.1 of the NRC Enforcement Policy (50-298/98007-12). Conclusions Performance of multiple tasks outside the scope of the outage position by the lead radiation protection technician was identified as the root cause of an event in which portions of the refueling floor were contaminated and four workers received uptakes of radioactive material. The area became airborne due to not keeping the area wetted as required by the radiation work permit. The calculated committed effective dose equivalent ranged from 2 to 6 mrem. This was a noncited violation of Technical Specification 5. H1.2 Failure to Sian Onto Proper Radiation Work Permit Inspection Scoce (71750)

i The inspectors reviewed instances in which workers entered the radiologically controlled !

area without signing onto the proper radiation work permi {

i Observations and Findinos  !

On October 25,1998, during the control rod drive change out, radiation protection ,

personnel identified that a contract worker entered a high radiation area without signing j onto the proper radiation work permit. The individual signed onto Radiation Work i I

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-26- l Permit 1998-0033. This permit did not allow entry into high radiation areas. The worker should have signed onto Radiation Work Permit 1998-1136 to enter the area. Once the radiation protection technician realized the worker was on the wrong radiation work permit, the worker was removed from the area and directed to sign onto the correct !

permit. The radiation protection technicians also verified that the dose in the area was l less than 2 mrem per hou '

On October 26,1998, two contract workers entered a high radiation area underneath !

the reactor vessel without signing onto the proper radiation work permit, Prior to arriving at the area, the two workers passed through at least two radiation protection check points. At these check points, radiation protection technicians checked the radiation l work permit and the dosimetry dose settings. The workers indicated they had signed l onto the proper radiation work permit when, in fact, they had not. The licensee interviewed the two individuals and concluded the individuals thought they had signed onto the correct permit, since both individuals had previously signed on the radiation work permit to perferrn work underneath the vesse On October 30,1998, an instrument and controls technician entered the drywell area to perform work underneath the vessel without signing onto the proper radiation work permit. The licensee performed an evaluation and determined that the individual was aware of the radiological conditions in the area prior to entering the drywel As corrective action, for each instance, the individuals were removed from the area, counseled, and required to sign onto the proper radiation work permit; a problem i identification report was written. In each of these instances, no workers received excess dose. The actual dose settings on the workers' dosimetry prevented them from receiving dose in excess of that allowed by the cerrect radiation work permi Failure to sign onto the proper radiation work permit is a violation of the Technical Specification 5.4.1 requirement to implement procedures for radiation protection. This l nonrepetitive, licensee identified and corrective violation is being treated as a noncited violation, consistent with Section Vll.B.1 of the NRC Enforcement Policy (50-298/98007- ,

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c. Conclusions During the outage, the licensee identified that in several instances workers entered high !

radiation areas without signing onto the proper radiation work permit. In each instance the licensee took appropriate corrective actio . .-- . - - ._ - ~. - ---- ..

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-27-R3 Status of Radiological Protection and Chemistry Facilities and Equipment l

R Anomalies in Personnel Dosimetrv  ; Inspection Scoce (71750)

l The inspectors followed up on anomalies with dosimetry that occurred when radiation workers were signing onto special work permit Observations and Findinas l

On September 8,1998, the licensee introduced new software for accessing the  !

radiologically controlled area. Soon after the outage began, radiation workers began to I notice errors in the setting of their PD 1 while logging onto special work permits. The licensee checked entries since the new program installation date and noted problems with approximately 800 entries into the radiologically controlled area. Of these entries, the licensee determined that six individuals received doses in excess of the preset dose alarm level. Although the dose was in excess of the preset dose alarm, the PD-1's did not alarm. The maximum dose received above the expected dose settings was 4.5 mrem. The maximum dose that rnight have been received was 20 mrem greater than the preset dose alarm. At this dose setting, the PD-1 would have alarmed. The licensee determined that no administrative dose limits were exceede The licensee contacted the vendor to determine the cause of the dose setting anomalies. The vendor stated the problem resulted from the battery tamper flag not being reset when entries into the radiologically controlled area were made. This flag caused the special work permit and radiologically controlled area work permit dose settings to be added by the PD-1 On October 8,1998, the licensee received and tested new software from the vendor that corrected this proble Conclusions After being informed of anomalies with dosimetry, radiation protection personnel responded quickly to identify whether any workers had received dose in excess of administrative limits. No workers had received excess dose. Radiation protection personnel also worked closely with the sof tware vendor to resolve the anomal X1 Exit Meeting Summary The inspectors presented the inspection results to members of licensee management at the exit meeting on November 12,1998. The licensee acknowledged the findings presente The inspectors asked the licensee whether any materials examined during the inspection should be considered proprietary. No proprietary information was identifie r: ,

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l ATTACHMENT l

l PARTIAL LIST OF PERSONS CONTACTED l

Licensee M. Boyce, Plant Engineering Manager J. Burton, Performance Analysis Department Manager P. Caudill, General Manager of Technical Services

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T. Chard, Radiological Manager

! . P. Donahue, Engineering Manager  !

C. Gaines, Maintenance Manager

!. T. Gifford, Engineering Manager B. Houston, Licensing Manager l M.. Kaul, Shift Supervisor D. Kunesmiller, Licensing Supervisor M. Peckham, Plant Manager J. Peters, Licensing Secretary -

B. Rash, Senior Manager of Engineering A. Shiever, Operations Manager

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INSPECTION PROCEDURES USED j i

IP 37551: Onsite Engineering IP 61726: Surveillance Observation IP 62707: Maintenance Observation IP 71707: Plant Operations IP 71750: Plant Support Activities IP 92901: Followup - Plant Operations IP 92902: Followup - Maintenance IP 92903: Followup - Engineering IP 92'700: LER - Onsite Review IP 93702: Onsite Response ITEMS OPENED, OPENED AND CLOSED, AND CLOSED gpened 50-298/98007 05 IFl Review the licensee's corrective actions for the service water coal tar coating degradation (Section M2.1).

50-298/98007-08 IFl . Review the licensee's corrective actions associated with faulty test instructions (Section E1.1).

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Opened and Closed 50-298/98007-01 VIO Failure to implement changes to plant procedures using the procedure process (Section O3.1).

50-298/98007-02 NCV Failure to recognize inoperable instrumentation and enter the applicable limiting condition of operation during a surveillance test (Section 04.1).

50-298/98007-03 NCV Operator error results in unexpected full scram on high scram discharge level (Section 04.2).

50-298/98007-04 NCV Technical Specifications violation due to missed testing of reactor building suppression chamber vacuum breakers (Section 08.1).

50-298/98007-06 NCV Failure to perform quality control requirements (Section M7.1).

50-298/98007-07 VIO Cycling valves prior to performing as-found testing (Section M8.1).

50-298/98007-09 NCV Failure to ensure adequacy of modifications (Section E1.2).

50-298/98007-10 NCV Failure to install properly rated fuses (Section E1.3).

50-298/98007-11 NCV Inadequate postmaintenance testing (Section E1.4).

50-298/98007-12 NCV Failure to follow radiation work permit during the disassembly of the drywell head (Section R1.1).

50-298/98007 13 NCV Failure to read and sign radiation work permit (Section R1.2).

Closed 50-298/98-008 LER Technical Specifications violation due to missed testing of reactor building suppression chamber vacuum breakers (Section 08.1).

50-298/98-009 LER Operator error results in unexpected full scram on high scram discharge level (Section 08.2).

50-298/97007-05 VIO Failure to include proper test criteria in procedures (Section M8.1).

50-298/97018-02 URI Corrective Actions and Root Cause Assessment of 4160 V Breakers (Section M8.2).

50-298/97018-03 IFl Adequacy of Licensee's Maintenance for 480 V Circuit Breakers (Section M8.3).

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50-298/97013-03 IFl Environmental Qualification of Low-Low Set System Pressure Switches (Section M8.4).

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l 50-298/97018-04 URI Adequacy of 125 Vdc Load and Voltage Study (Section E8.1).

l 50 298/97.-014- LER . Station Modification Creates Potential Inability to Mitigate Accident Consequences (Section E8.2).

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