IR 05000285/1995024

Insp Rept 50-285/95-24 on 951217-960127.Violations Noted. Major Areas Inspected:Operational Safety Verification,Plant Support Activities,Maint & Surveillance Observations,Onsite Engineering & Open Item Followup

ML20149L494
Person / Time
Site:	Fort Calhoun
Issue date:	02/08/1996
From:	Pellet J NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION IV)
To:
Shared Package
ML20149L486	List: IR 05000285/1995024 ML20149L483 ML20149L492
References
50-285-95-24, NUDOCS 9602260383
Download: ML20149L494 (17)

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ENCLOSURE 2 U.S. NUCLEAR REGULATORY COMMISSION

REGION IV

NRC Inspection Report: 50-285/95-24 Operating License: DPR-40 Licensee: Omaha Public Power District Fort Calhoun Station FC-2-4 Ad l P.O. Box 399, Hwy. 75 - North of Fort Calhoun l Fort Calhoun, Nebraska Facility Name: Fort Calhoun Station Inspection At: Blair, Nebraska Inspection Conducted: December 17, 1995, through January 27, 1996 Inspectors: W. Walker, Senior Resident Inspector V. Gaddy, Oesident Inspector Approved:

JoERiL. Pellet, Acting Chief, Project Branch A b-h Date Inspection Summary Areas Inspected: Routine, announced inspection or operational safety verification, plant support activities, maintenance and surveillance observations, onsite engineering, and open item followu Results:

Plant Operations

• The response to the low river level was excellent. Very good .

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contingency plans were established. The decision to begin reactor shutdown prior to the Technical Specification required shutdown was conservative (Section 2.1).

• The response to the hydrazine spill was good. The effort of containing '

and cleaning up the spill was also good (Section P.2).

• A lack of understanding of the maintenance work control procedure resulted in deficiency tags not being hung on feedwater control valves (Section 3.3).

9602260383 960222 PDR ADOCK 05000295 G PDR

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• A nonlicensed operator failed to follow a procedure and opened an incorrect valve on the raw water / component cooling water heat exchange This potentially could have allowed the component cooling water postaccident temperatures to be exceeded. This resulted in a violatio (Section 3.4).

• A pressure perturbation in the chemical and volume control system resulted in pressure switches failing off-scale high and an isolation of letdown flow. Operator response during the event was very goo Efforts to determine the cause and subsequent effects of the pressure perturbation were adequate (Section 3.5).

Maintenance

• The licensee's investigation into damaged yoke bushings on the charging pump suction valves was not comprehensive in that other valves that may have been susceptible to the same failure mechanism were not inspected until questions were posed by the inspectors (Section 5.2).

• After repair of a charging pump suction valve, maintenance personnel failed to remove the deficiency sticker and did not inform operations that the sticker was to remain on the control board. This was an example of a lack of effective communication between the two organizations (Section 5.3).

• The maintenance planning and coordination for sealing compound injection into a feedwater heater bypass valve was not thorough. This resulted in the valve being permanently sealed closed (Section 5.4).

• The inspectors questioned the method of independent verification being used by maintenance personnel. Maintenance personnel corroborated on the action to be performed prior to accomplishing the task, thereby potentially invalidating the independence of the task verifier (Section 6.2).

• The corrective action taken in October 1995 to prevent unexpected starts i of the steam driven auxiliary feedwater pump was narrow and did not i prevent recurrence of another unexpected start in January 1996 l (Section 6.3).

Engineering

• The licensee procured commercial grade pressure switches and installed them in applications maintaining the reactor coolant pressure boundar i The adequacy of the licensee's corrective actions are an unresolved item (Section 7.3).

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! * Licensee design control measures did not assure that an adequate i quantity of trisodium phosphate was available~to neutralize containment

sump pH following a loss of coolant accident. This resulted in a d

violation (Section 7.1).

Plant Support i

! * A lack of ' attention to detail resulted in a radiological survey map not t' being posted as expected by licensee management (Section 4.1). -

Summary of Inspection Findings:

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• Unresolved Item 285/9524-03 was opened (Section 7.3).

4 * Violation 285/9524-01 was opened (Section 3.4).

• Violation 285/9524-02 was opened (Section 7.1).

Violation 285/9517-01'was closed (Section 8.1).

i e Violation 285/9517-02 was closed (Section 8.2).

Violation 285/9519-01 was closed (Section 9.1).

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Unresolved Item 285/9521-01 was closed (Section 7.1)

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< Attachment:

• Persons Contacted and Exit Meeting

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-4-DETAILS 1 PLANT STATUS The plant operated at 100 percent power throughout this inspection perio ONSITE RESPONSE TO EVENTS (93702)

2.1 Low River Water Level On January 19, 1996, the licensee entered Abnormal Operating Procedure-01 for low river water level. The river level started to decrease and at 6 a.m. was at 986 feet and 7 inches. The rate of decrease was approximately 1 to 2 inches per hour. The decrease was occurring because of an ice jam on the Missouri River approximately 90 miles north of Fort Calhoun Station. The Corp of Engineers was predicting that the river would drop to approximately 980-982 feet at the plant. On January 20, at 2:21 p.m., the licensee made a 4-hour report to the NRC as required per its procedures. The river level at that time was 983 feet. It continued to drop and the lowest level reached was 982 feet 6 inches. On January 21, the river level had started to return to normal and the Abnormal Operating Procedure-01 was exited at 12:10 The river at that time was at 987 feet 2 inche The inspectors observed the licensee's contingency planning during this low river level condition and observed excellent briefings given to the operating crews prior to manning their shifts. Activities were performed in a controlled and effective manner. The licensee management also discussed with the operations personnel several conservative actions that would be taken based on plant observed conditions. If the plant at any time began to experience trouble with the circulating water system, the intention was to reduce power to 50 percent or below. Additionally, licensee management decided to begin a reactor shutdown at the 979 foot river level rather than the Technical Specification required level of 978 feet. On the basis of the high level of communications the licensee provided to the inspectors to keep them informed of the changing river level conditions and the conservative approach to responding to decreasing river water level, the inspectors concluded that the licensee's performance was excellent in response to this even .2 Hydrazine Spill l On January 24, 1996, the licensee made a 4 hour4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> nonemergency report to the NRC following discovery of a hydrazine spill in the turbine buildin The amount of hydrazine spilled was approximately 50 gallons. The leak was contained inside a special berm and also a ventilation hood which precluded the fumes i from affecting other areas of the plant. The licensee's hazardous materials !

team was called to the site and appropriate clean up of the spill was conducte , .- - .. . - . - - . - . - - -. .= . . - - .-. --- _ - - . .. - - -

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-5-The inspectors questioned the licensee concerning the cause of the spill and were informed that the spill resulted from leakage out of the top of the lower hydrazine container. The hydrazine is staged in two stainless steel containers, one on top of the other. The top container is changed when necessary and then gravity feeds into the lower container where the suction to the chemical feed pumps is located. In discussions with the system engineer, the inspectors were informed that the top access cover for the lower container had been loosened the day before by the licensee staff to inspect the tank contents and apparently was not adequately resealed, resulting in the leakag The inspectors concluded that the licensee efforts to contain and clean up the hydrazine spill was goo OPERATIONAL SAFETY VERIFICATION (71707)

3.1 Routine Control Room Observations The inspectors observed operational activities throughout this inspection period to verify that adequate control room staffing and control room professionalism were maintained. Shift turnover meetings were conducted in a manner that provided for proper communication of plant status from one shift to the other. Discussions with operators indicated that they were aware of plant status, equipment status, and reasons for illuminated annunciator Control room indications of various valve and breaker lineups were verified for current plant status, s

3.2 Plant Tours The inspectors routinely toured various areas of the plant to assess the safety conditions and adequacy of plant equipment. The inspectors verified that various valve and switch positions were correct for the current plant conditions. Piping and instrumentation drawings and operating instructions posted in vital areas were inspected and found to be current. Personnel were observed obeying rules for escorts, visitors, and entry and exits of vital area l 3.3 Deficiency Taqqing i On January 10, 1996, the inspectors observed packing leaks on two valves which did not have deficiency tags attached to them, Feedwater Level Control i Valve LCV-1304 and low pressure Feedwater Heater Level Control Valve LCV-120 The inspectors discussed these valves with operations personnel and were l informed initially that these valves would not have to be deficiency tagged l and could be repaired under Standing Order 50-M-101, " Maintenance Work 1 Control," Revision 3 This standing order contains a section for minor maintenance specified as tool pouch maintenanc During initial discussions with the operations personnel, the inspectors were informed that the repair of the two valves likely could be completed using tool pouch maintenance since the valves were part of the balance of plant equipment. The inspectors performed further review of Standing Order S0-M-101 and discussed the valves )

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-6-with a maintenance planner who informed the inspectors that the standing order specifies that packing adjustments can be performed on manual valves not subject to surveillance testing. However, since both of these valves were air operated valves, work could not be performed on these valves without a maintenance work order per the standing order guidanc The inspectors questioned operations personnel on whether training on the minor maintenance standing order had been performed and were informed that it had. The operations manager also informed the inspectors that each crew would be given a refresher briefing on the tool pouch maintenance portion of Standing Order S0-M-101, to ensure that the requirements for this type of maintenance were understoo The inspectors verified through selective interviews with operations personnel that the refresher briefings were conducte .4 Component Cooling Water. Raw Water Heat Exchanger Cleaninq On January 15, 1996, an equipment operator was performing a pressure test of Component Cooling Water Heat Exchanger AC-l The heat exchanger had been removed from service for scheduled cleaning. The operator was using Maintenance Procedure PE-RR-CCW-0100, Revision 11, to perform the pressure tes Step 6.14.1 directs the operator to open Inlet Component Cooling Water Valve HCV-491A to the subject heat exchanger. Contrary to this procedure the ;

operator opened both the inlet valve and the outlet valve to the heat exchanger and both valves remained open until discovered by licensee personnel on January 17. While there was no effect on system operation for the existing plant conditions, this error challenged postaccident operation as described belo Operations Memorandum 95-07, " Post Accident Component Cooling Water System Performance," specifies controls needed to maintain component cooling water temperature below 160*F as required by the licensee's design basis analysis for a loss of coolant accident or main steam line break. The opening of both the inlet and outlet component cooling water valves could have potentially .

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allowed the 160aF temperature limit to be exceeded due to component cooling water bypass through the not-in-service heat exchange The licensee initiated Condition Report 199600063 to document this error, which had the potential to adversely affect plant response to a design basis accident and would have required operator recognition and action to return the component cooling outlet valve to the handjacked closed position as require The inspectors discussed with the operations manager actions which had been instituted to ensure that the above problem was addressed. The licensee has '

discussed Operations Memorandum 95-07 with all operating crews and required that all licensed operators review all operations memorandums to refamiliarize themselves with the requirements. In addition the condition report was elevated to a Level 1 priority, which required that a root cause for the valve

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-7-mispositioning be determined. This was assigned to the Nuclear Safety Review Group. Lastly, Operating Instruction 01-RW-1, " Raw Water System Normal Operation," Revision 37, and Operating Instruction 01-CC-1, " Component Cooling System Normal Operation," Revision 22, were being revised to ensure that the requirements of Operations Memorandum 95-07 was adequately incorporate The failure to follow Maintenance Procedure PE-RR-CCW-0100, Revision 11, when pressure testing the heat exchanger is a violation (285/9524-01).

3.5 Chemical Volume Control S_ystem Pressure Perturbation On January 22, 1996, the licensee experienced pressure perturbations on the chemical volume control system, specifically the letdown portion of that system. Operations personnel had begun. to increase letdown flow and were placing a second charging pump in service when letdown pressure began to oscillate and eventually caused the letdown system to isolate automatically as designed. The inspectors were in the control room during the perturbation and noted that operator performance during the event was very good. The licensee initiated Condition Report 199600075 to document the pressure oscillatio The licensee identified that two Pressure Switches PIC-242 and PIC-243 had gone off scale high. These pressure switches provide an isolation signal to Valve HCV-204, which is the letdown stop valv The inspectors questioned the licensee concerning the maximum pressure reached in the letdown system piping and whether any damage potentially occurred to the piping. The inspectors discussed the pressure perturbation with the system engineer and were informed that the pressure switches which went off scale contained a mechanical linkage which could become disconnected if the switches experience rapid pressure fluctuations. The system engineer informed the inspectors that the system contained Letdown Safety Valve CH-223, which was designed to prevent over pressurization of the letdown system piping due to the fact that the valve was designed to lift from overpressure at 650 psi During investigation of the event, the licensee discovered that Letdown Accumulators CH-29 A and B were not fully charged. Accumulator A contained 220 psig of nitrogen gas and Accumulator B was empty. The accumulators are designed to contain 235 psig of nitrogen. These 5 gallon accumulators allow letdown flow to pass through them and absorb pressure fluctuations in the letdown system and aid in controlling letdown flo The licensee determined that Accumulator B being depressurized limited its pressure dampening capability, which was the primary cause of the excessive pressure perturbations. The accumulators were a modification which was added to the letdown system approximately 3 years ago to prevent pressure fluctuations. Initially the accumulators were on a preventive maintenance order (PM0) of every 6 months for nitrogen charging; however, due to the fact that the area where the accumulators were located was a high radiation area and for several PM0 cycles the accumulators maintained their nitrogen charge,

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-8-the licensee decided to extend the PM0 to every outage. Based on this event, the licensee is considering reinstituting the 6-month PM The inspectors considered the licensee's efforts to determine the cause and subsequent effects of the pressure perturbation to be adequat PLANT SUPPORT ACTIVITIES (71750) Radiological Protection Program Observations During this inspection period, the inspectors verified that selected activities of the licensee's radiological protection program were properly implemented. Health physics personnel were observed routinely touring the radiologically controlled areas. Contaminated areas and high radiation areas were posted, and restricted high radiation areas were found to be locked, as require .2 Security Program Observations The inspectors observed various aspects of the licensee's security progra Security personnel were found to perform their duties in a professional manner. Vehicles were properly controlled or escorted within the protected area. Designated vehicles parked and unattended within the protected area were found to be locked and the keys removed. The inspectors routinely toured the protected area perimeter and found it maintained at an excellent leve Proper compensatory measures were observed when a security barrier was inoperabl .3 Radiological Surveys On December 27, 1995, during a routine tour of the radiological controlled area, the inspectors noted that the radiological survey for Room 10 (Monitor Tank Room) was dated October 16, 1995. The inspectors brought this to the attention of radiation protection personnel and the survey was immediately updated. The inspectors verified that the survey had been performed and survey results were posted outside the radiological controlled area and not on the door to Room 10, inside the radiological controlled area. The inspectors reviewed the licensee procedures and determined that although the surveys were not required to be posted they could be posted for reference prior to entering applicable area The inspectors asked licensee management if the failure to post the survey met their expectations. Licensee management stated that it did not and that the surveys were expected to be posted on each door after surveys were complete The licensee then initiated Condition Report 199500450 to document the 1 discrepancy. The licensee stated that the reason the survey had not been ,

changed was because the form that was used to verify posting of survey maps I was revised in September 1995 to reflect new survey frequencies, and Room 10 l had been inadvertently omitted from the revised form. The licensee then l

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-9-changed the verification sheet to include Room 1 No other examples were identified. The inspectors concluded that this oversight constituted a lack of attention to detail by radiation protection personne MAINTENANCE OBSERVATIONS (62703)

The maintenance activities listed below were observed and documentation reviewed-to verify that the activities were conducted in a manner which resulted in reliable safe plant operatio .1 Maintenance Observations The following maintenance activities were observed:

• Overhaul of Feedwater Pump FW-4C

• Cleaning of Raw Water Component Cooling Water Heat Exchanger AC-lC

• Rebuilding of Raw Water Pump AC-108 No problems were identified during these observations. Issues stemming from the review of other maintenance activities are noted belo .2 Charging Pump Yoke Bushings On December 18, 1995, while isolating Charging Pump IC during the performance of Surveillance OP-ST-CH-3003, " Chemical & Volume Control System Pump / Check Valve Inservice Test," the yoke bushing on Valve CH-172 failed. A similar failure occurred to the yoke bushing for Valve CH-174 on December 22 while isolating Charging Pump CH-1A during the performance of the same procedur Both valves were inlet isolation valves. The licensee initiated Condition Reports 199500407 and 19950043 In both incidences, replacement parts were not on site. The licensee '

initiated emergency temporary modifications to remove the yoke bushing from unused Valves CH-131 and CH-134 (Boric Acid Filter Inlet and Outlet, respectively) to replace the valve yokes noted above. The licensee installed clamps on the filter inlet and outlet valves to keep them close Although these valves were in the chemical and volume control system, the boric acid filter had never been in service and was isolate The licensee suspected that failures were due to a lack of lubricant being applied to the valve's stem. Over time, the licensee suspected that friction caused the valve to fail. The licensee inspected the inlet isolation valve for Charging Pump CH-18 (CH-173) and did not note any degradation in the valve. Further investigations revealed that there was a yearly preventive maintenance (PM) requirement for the valves, but the PM was for inspection only and did not require the stem to be lubricated. The licensee indicated that the PM would be amended to require that the stem be lubricated during 'l

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i yearly inspections. This' type valve is used in over 50 other applications in the plant, some in safety-related system On January 22, 1996, the inspectors asked if other valves had been inspected to determine if they lacked the needed lubricant. The licensee stated that other valves had not yet been inspected. The licensee initiated a maintenance work request to have

'the valves inspected and lubricated as neede The inspectors considered the licensee's investigation to be not comprehensive, in that, valves that may be subject to the same failure mechanism had not been inspected nor had plans been initiated to inspect the valves until questions were posed by the inspector .3 Work Request Tag On December 29, 1995, during a walkdown of the control boards, the inspectors noted that Work Request Sticker 9504075, dated December 22, had not been removed from Charging Pump CH-I The sticker was written to repair the pump's suction valve. The inspector questioned an operator and the operations

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supervisor, and both indicated that the sticker should have been removed by maintenance personnel following the repair of Valve CH-174. The operator was aware that the charging pump had been repaired. Further investigation determined that maintenance personnel did not remove the sticker because they were holding the work pack ge open until the yoke bushings removed from Valves CH-131 and CH-134 'ld be reinstalled. The basis for keeping the work package opened was not prc.ided to operations. Operations personnel stated that they relied on the stickers to provide them with an indication of plant equipment. The failure of maintenance to inform operations that the stickers would not be removed from the control room until Valves CH-131 and CH-134 were repaired indicated a lack of effective communication between the two organization Although, in this instance, the operator questioned by the inspectors knew the status of tagged equipment, this incident uncovered a potential vulnerability in that operators may not be fully aware of the status of plant equipmen .4 Low Pressure Feedwater Heater Bypass Valve On December 27, 1995, the inspector observed contract personnel attempt to inject a sealing compound into Valve FW-749 (Low Pressure Heater 14A bypass inlet equalizing valve). The sealant was to be injected into the body to bonnet joint of the valve to stop a steam lea Injection would have stopped the steam leak until the plant was shut down and the leak permanently repaired. The work was being conducted in accordance with Maintenance Work Order 954161 and Temporary Modification 95-052. During initial inspection of the valve prior to injection, contract personnel questioned configuration of the valv j

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Further investigation revealed that the contractors had not been provided with the correct valve configuration. The contractors were prepared to inject into i

a face-to-face body-to-bonnet valve. During the initial valve inspection, the l

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-11-contractors discovered that the valve was not a face-to-face valve, but there was a 1/16 inch gap in the valve. Since the contractors were provided the incorrect valve description, the job had to be stopped and procedures had to be revised. This resulted in the work not being completed until the next da Since the incorrect valve configuration had been provided, the licensee decided to use the contractor's valve " kill" procedure and inject compound between the gate and flange bonnet. The licensee had rejected all other options proposed by the contractor for repairing the valv By injecting between the gate and flange bonnet, the valve would be permanently sealed closed, which eliminated the capability to bypass this feedwater heater (not normally used). The inspectors noted that, prior to its use, the valve " kill" procedure was approved by the plant review committe The inspectors observed the compound injection and noted that it was completed in a safe, effective manner, without any additional anomalie The inspectors concluded that the work was not thoroughly planned and coordinated with contract personnel. The lack of planning also resulted in a delay in repairing the valv SURVEILLANCE OBSERVATIONS (61726)

The inspectors observed the surveillance testing listed below to verify that-the activities were performed in accordance with the licensee's approved programs and the Technical Specification .1 Surveillance Observations The following surveillance activities were observed:

• RE-ST-NI-0001, "Cecor/Excore Offset Check," Revision 14

• OP-ST-DG-0001, " Diesel Generator Check," Revision 16

'No problems were identified during these observation Issues stemming from l the review of other surveillance activities are noted below, i

6.2 Auxiliary Feedwater Functional Check of Initiation Circuits

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i On December 20, 1995, the inspectors observed instrumentation and control i personnel perform portions of a surveillance to verify operability of the auxiliary feedwater automatic initiation circuits. The test was being performed in accordance with Revision 9 of Procedure IC-ST-AFW-0001, " Auto Initiation of Auxiliary Feedwater Functional Check of Initiation Circuits."

Instrumentation and control personnel were performing the Channel A sensor logic check. The test was conducted inside Panel AI-196, " Auxiliary Feedwater System Channel A Auto Actuation Panel." The inspector noted that maintenance personnel exhibited good safety practices. During the surveillance, the inspectors questioned the independent verification methods used by the l

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-12-technicians. The inspectors noted that, when technicians came to steps in the procedure that required independent verification, both technicians mutually agreed'on and pointed out the equipment that was to be manipulated. Then one technician turned away while the other technicians performed the step. The technicians that turned away would then verify that the task had been accomplished as agreed o The inspectors asked licensee management if this method of independent verification was acceptable, since both technicians agreed on the action prior to it being taken. The inspectors also asked if this met the intent of Standing Order 50-G-4, " Fort Calhoun Station Quality Verification Program,"

which required independent verification to be accomplished completely independent of the activity being performed. Licensee management stated that this method met their expectation and that they believed it also met the intent of the standing orde The inspectors questioned whether this method met the intent of the standing order since technicians corroborated on the action to be performed prior to accomplishing the task, which appeared to negate the independence of the tasks. Licensee personnel indicated they would examine this practice to ensure it is consistent with industry standard .3 Steam Driven Auxiliary Feedwater Pump On January 5, 1996, during the performance of SE-ST-AFW-3005, " Auxiliary Feedwater Pump FW-6 and Check Valve Test," the steam-driven auxiliary feedwater pump (FW-10) unexpectedly started. The licensee documented this unexpected start in Condition Report 199600013. This event appeared to be identical to a similar event that occurred in July 199 This event is documented in NRC Inspection Report 50-285/95-1 During both events, licensed operators had previously placed the hand control switch!for Valve YCV-1045 (steam inlet valve) in the CLOSED position. While attempting )

to restore the hand control switch for Valve YCV-1045 in the AUTO position, i the steam inlet valve opened, resulting in a pump start. In the January 1996 incident, the licensee suspected that the operator manipulating the switch overshot the AUTO to the OPEN hand switch position, which caused the steam inlet valve to reope The corrective action for the July 1995 failure was to replace the hand control switch. The switch was replaced in October 1995. The licensee suspected that wear or loose contacts were the reason for the unexpected start. As a result, the switch was replaced and no specific guidance on how to manipulate the switch was given to the operators. However, it appears the corrective action from the July 1995 pump start was limited in that it did not ,

thoroughly address switch manipulation nor was a root cause determination !

I mad i Based on the investigation performed during the January 1996 pump start, the I licensee was confident that the problem was due to how the switch was being l manipulated and not the control circuitry. As 4 result, the system engineer '

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d-13-was developing a modification package to change the style of the switch. The new design would improve the cam design and provide a more definitive locking position to prevent overshoot while changing switch positions. In the interim, the system engineer planned to brief operating crews prior to surveillance testing on the importance of not overshooting the desired switch position and on the consequences if overshooting does occu The inspectors noted that no operability concern exists because, if an autostart signal is received, the pump would start and perform its intended safety functio ONSITE ENGINEERING (37551)

7.1 Reactor Coolant Gas Vent System On January 5, 1996, the inspectors discussed with the licensee the reactor coolant gas vent system leakage which had been observed by the inspectors during a tour of the control room. The licensee had been monitoring this leakage throughout the cycle and on December 21, when performing a walkdown of the containment, the licensee discovered that there was leakage by the vent to Containment Isolation Valve HCV-181 and Quench Tank Isolation Valve HCV-180 as evidenced by an increase in the level of the quench tank. Both of these valves are part of the reactor vessel head and pressurizer venting system that would be used to remove noncondensable gases during an acciden The licensee has been tracking the leakage, which is approximately 0.07 gallons per minute (gpm). Currently, it does not appear that the leakage ..

is increasing. The licensee has established a team to formulate a plan for potential repair or operation with the valves as is until the refueling outage in September 1996. The licensee is continuing to monitor and track leakage and is actively pursuing repair or potential replacement of the isolation valves in the reactor coolant and gas vent syste .2 Non-C0E Pressure Boundar_y Instrumentation During a review of Engineering Change Notice 93-247, which replaced the pressure switches for each safety injection tank (SIT), the licensee staff internally questioned how Seismic Category 1 instrumentation could be replaced with noncritical quality equipment (non-CQE) instrumentation. From the review, the licensee discovered that the CQE pressure switches on the safety injection tanks had been replaced with non-CQE pressure switches. These instruments had been purchased as commercial grade and were installed during the 1995 refueling outag The licensee conducted an investigation and determined that the data contained in their computerized plant equipment list (CHAMPS) were not correct. In the CHAMPS database numerous pressure switches and line transmitters were incorrectly identified as being non-CQE and Seismic Class 1 items. Since the database identified the pressure switches as non-CQE equipment, replacements

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-14-i were procured as non-CQE equipment. On January 11, 1996, the licensee

identified this discrepancy in Condition Report 19960004 Since the pressure switches for the SITS were purchased as commercial grade, they had not been adequately pressure tested for the application of maintaining the RCS pressure boundar Failing to ensure that the pressure

switches were purchased according to the codes and specifications of the j original switches is a violation of Step 5.1.4.8 of Procedure PED-GEI-32,

" Instructions for Preparing Material Evaluation Reports and Material Procurement Plans," which requires, in part, that replacemer,t items be

purchased to specifications and codes equivalent to those specified for the original equipment. The licensee has implemented immediate and long-term corrective actions to prevent recurrence of the erroneous procuremen The licensee conducted an operability evaluation to determine if the pressure switches were capable of maintaining the RCS pressure seen by the safety injection. tanks. The operability evaluation determined that the pressure i switches were operable because they were rated up to 350 psig and the relief valves on the SITS lifted at 275 psig, limiting potential exposure to high pressure The licensee also identified other instruments in CHAMPS that may have been incorrectly identified as non-CQE equipment. These instruments were used  ;

throughout the plant. The licensee identified a total of 201 instruments that potentially could have been replaced with non-CQE equipment due to the errors in the CHAMPS database. These suspect instruments were documented on '

Condition Report 199600070, dated January 19, 1996. The effort of identifying the CQE instruments that may have been replaced with non-CQE instrumentation was conducted over the course of several days. As potentially susceptible instruments were identified, the licensee did not make immediate operability determinations. lhe licensee waited until all instrumentation was identified before beginning the process of making operability determinations instead of making operability determinations as the deficiencies were identified. This was an example in which operability determinations were not being made in a timely manner. At the conclusion of the inspection period, no additional instrumentation has been identified that required operability evaluation For the 201 instruments, the licensee used probabilistic risk assessment to aid in prioritizing which instruments should be evaluated first, based on their safety significance. The instruments were assigned priorities of 1 - 4, with 1 being highest priorit During the condition review meeting in which Condition Report 199600070 was reviewed, the corrective action group had assigned this condition report a condition level of Level 4 condition reports were not required to have root cause analysis performed. The inspector noted that the plant manager i upon reviewing the condition report directed that the condition report would i be increased to Level 1, which required a root cause analysis, and that it be :

brought back to the plant review committee prior to closure. In this instance l

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it appeared that the corrective action group was not fully cognizant of the safety significance because its recommendation did not require that a root cause be performe Since the licensee staff was confident they had identified all potentially susceptible instruments, they planned to determine the required hydrostatic test pressure and hold time for each system with potentially susceptible instrumentation, determine seismic installation requirement for non-CQE instrumentation with a CQE pressure boundary, and determine the maximum pressure that applicable instrumentation has already been subjected to through tests and calibrations. These actions were scheduled to be completed by February 5, 1996. Based on the results of these findings, operability determinations and evaluations will be made. The licensee also planned to provide guidance by February 9, 1996, to system engineering, procurement, and maintenance planning to ensure instrumentation that has been purchased or installed was properly tested and met quality assurance requirements. In addition, numerous other corrective actions were planned by the licensee to prevent recurrence. All corrective actions were scheduled to be implemented by February 24, 1996. This item is unresolved pending the NRC. review of the licensee's evaluations and implementation of its proposed corrective actions (Unresolved Item 285/9524-03).

8 FOLLOWUP - PLANT OPERATIONS (92901) (Closed) Violation 285/9517-01: Failure to Properly Reset Diesel Generator Governor Switch The inspector verified the corrective actions in the licensee's response letter dated December 6, 1995, and considered them to be reasonable and complete. No similar problems were identifie .2 (Closed) Violation 285/9517-02: Failure to Properly Correct a Procedural Inadequacy This failure to properly address an inadequacy in the Emergency Diesel Generator 2 procedure, as discovered during testing of the diesel in March 1995, resulted in a similar event recurring on August 24, 1995. The !

inspector verified the corrective actions described in the licensee's response letter dated December 9 and considered them to be reasonable and complete. No similar problems were identifie FOLLOWUP MAINTENANCE (92902) (Closed) Violation 285/9519-01: Failure to Maintain Work Documentation at the Work Site This violation was due to the licensee's failure to ensure work documentation was maintained at the work site during performance of maintenance activities

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-16- l as required by Standing Order S0-M-100. The inspector verified the corrective actions described in the licensee's response letter dated December 22, 1995, and considered thern to be reasonable and complet FOLLOWUP ENGINEERING "(92903)

1 (Closed) Unresolved Item 285/9521-01: Trisodium Phosphate Inside containment On December 4, 1995, the licensee reported a plant condition outside the design basis. Specifically, it was identified that the quantity of trisodium phosphate in the containment sump necessary to neutralize the boric acid from the containment spray and safety injection systems after a loss of coolant accident was less than required. The trisodium phosphate is necessary to reduce the potential for chloride induced stress corrosion cracking in certain

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materials, specifically, stainless stee This has been an ongoing issue which the licensee has been pursuing and, on November 28, the licensee obtained a new calculation utilizing a conservative methodology from the

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nuclear steam system supply vendor. Based on the licensee's review and evaluation of the significance of this updated calculation, the licensee

, concluded that the quantity of trisodium phosphate stored inside containment at times has not been sufficient to neutralize sump water to a pH greater than seven, which is the licensing basis for the Technical Specification 3.6.2(d)

requiremen Inadequate design control measures for design changes had been

- implemented by the licensee for assuring _the quantity of trisodium phosphate was sufficient to neutralize containment sump water during all plant conditions. This is a violation of NRC requirements (285/9524-02).

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J ATTACHMENT 1 PERSONS CONTACTED Licensee Personnel

• R. Andrews, Division Manager, Nuclear Services

• C. Brunnert, Supervisor, Operations Quality Assurance

• J. Chase, Manager, Fort Calhoun Station

• G. Cook, Supervisor, Station Licensing

• H. Faulhaber, Supervisor, Maintenance

• S. Gambhir, Division Manager, Production Engineering

• J. Herman, Manager, Outage Management

• R. Jaworski, Manager, Station Engineering

• D. Leiber, Supervisor, Security Support Services

• E. Matske, Licensing Engineer-

• T. Patterson, Division Manager, Nuclear Operations

• R. Short, Acting Manager, Operations

• D. Spires, Manager, Chemistry

• M. Tesar, Manager, Corrective Action Group

• D. Trausch, Manager, Nuclear Licensing '

2 EXIT MEETING An exit meeting was conducted on January 29, 199 During this meeting, the inspectors reviewed the scope and findings of the report. The licensee did not express a position on the inspection findings documented in this repor The licensee did not identify as proprietary any information provided to, or reviewed by, the inspector _ _ - _ _ _ _ _ __ _. _ - - .