IR 05000331/1999007

Insp Rept 50-331/99-07 on 990526-0707.No Violations Noted. Major Areas Inspected:Operations,Maint,Engineering & Plant Support

ML20210B544
Person / Time
Site:	Duane Arnold
Issue date:	07/16/1999
From:	NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION III)
To:
Shared Package
ML20210B533	List: IR 05000331/1999007 ML20210B527
References
50-331-99-07, NUDOCS 9907230169
Download: ML20210B544 (18)

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,. U. S. NUCLEAR REGULATORY COMMISSION REGION 111 Docket No: 50-331 License No: DPR-49 Report No: 50-331/99007(DRP)

Licensee: Alliant, IES Utilities In First Street P. O. Box 351 Cedar Rapids, IA 52406-0351 Facility: Duane Arnold Energy Center Location: Palo, Iowa Dates: May 26 through July 7,1999 Inspectors: P. Prescott, Senior Resident Inspector M. Kurth, Resident inspector Approved by: M. N. Leach, Chief Reactor Projects Branch 2 Division of Reactor Projects

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' EXECUTIVE SUMMARY Duane Amold Energy Center NRC Inspection Report 50-331/99007(DRP)

This inspection report included the resident inspectors' evaluations of aspects of licensee operations, engineering, maintenance, and plant suppor Ooerations

. . The inspectors concluded that overall conduct of operations continued to be professional, with appropriate focus on safety (Section 01.1).

. On two occasions operating crews did not enter the appropriate Technical Specification limiting condition for operation (LCO). On May 24,1999, the licensee entered the wrong LCO when a reactor recirculation mini-purge isolation valve failed to close and was declared inoperable. A Non-Cited Violation for failing to log the appropriate LCO. Also, on June 23,1999, the inspectors identified that the proper 72-hour Technical Specification LCO was not entered for having a low pressure emergency core cooling .

system and the high pressure coolant injection system inoperable during surveillance testing (Section 01.2).

-. The plant shutdown and startup in support of the forced outage for repairs to the primary containment electrical penetration repairs were well controlled evolutions. Good teamwork was noted between the various licensee departments to support the maintenance activities. The shutdown to repair the penetration conductors demonstrated a conservative plant operating philosophy (Section 01.3).

. In September 1998, the "A" control building chiller was declared inoperable due to the licensee's determination that the "A" cooling coil chill water control valve's air supply was not from a safety-related source. Technical Specification 3.7.5 required that with one control building chiller subsystem inoperable, that the subsystem be retumed to operable status within 30 days. This condition was believed to have existed since initial

. startup. Therefore, a Non-Cited Violation resulted from the failure to meet Technical Specification requirements (Section 08.2).

Maintenance

. The repairs for the shorted conductors in the primary containment electrical penetration

.1JX105A were well planned and executed. There was one minor error due to lack of attention to detail introduced during planning and which was also missed during restoration of a conductor; however, the overall repair activities were completed satisfactorily (Section M1.2).

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. The engineering evaluation for the installation of the modified pump test retum line throttle valve, V33-0156, was deficient. The evaluation contained an incorrect description of how the general service water system strainer system operated. The amount and type of debris in the water was underestimated. The hole size for replacement valve V33-0150 was less than the strainer hole size for the pump and the

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. I cooling tower; therefore, V33-0156 acted as a strainer. Also, the engineering evaluation lacked adequate documentation to support its conclusions (Section E1.2).

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The Year 2000 readiness review was completed with acceptable results (Section E8.1).

Plant Sucoort

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The inspectors determined that radiation protection personnel appropriately restricted access to areas within the reactor building in response to a radiological contamination spill. The licensee was effective in its decontamination efforts (Section R1.1).

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Report Details Summarv of Plant Status The licensee operated the plant at 100 percent power at the beginning of the inspection perio On June 6,1999, at 8:10 a.m., the licensee initiated a controlled reactor shutdowri for a forced maintenance outage to repsir four electrical conductor shorts that occurred in the same primary containment electrical penetration. The licensee moved the conductors, including other conductors in close proximity, to spare conductors in the same penetration. Following repairs, operators commenced a reactor startup on June 14,1999. The main generator was placed on the grid June 15,1999, at 10:14 a.m. Full power was essentially reached on June 18,199 The licensee maintained the unit at full power for the remainder of the inspection perio l. Operations 01 Conduct of Operations 01.1 General Comments Inspection Scone (71707)

The inspectors followed the guidance of Inspection Procedure 71707 and conducted frequent reviews of plant operations. These inspection activities included observing routine control room and in-plant activities, attending shift tumovers and crew briefings, and performing panel walkdown Observations and Findinos The conduct of operations continued to be conservative and appropriately focused on safety. The inspectors observed strict use of procedures and thorough shift tumover ,

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The inspectors noted that the licensee sent a group of operations personnel to another site and more visits are planned in order to gauge overall operations performance within the industry. The inspectors noted, in discussions with operations personnel, that the response to this initiative was found to be positive, Conclusbns The inspectors concluded that overall conduct of operations continued to be professional, with appropriate focus on safet .2 Technical Specification (TS) Entries Inspection Scope (71707)

The inspectors observed two occasions during the report period when operators made improper TS entries. The inspectors reviewed the circumstances involving both examples. Documents that were reviewed included:

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Duane Amold Energy Center Technical Specifications Administrative Control Procedure (ACP) 1410.7, " Guidelines for Primary Containment Valves and Penetrations," Revision 9

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ACP 1410.2, "LCO Tracking and Safety Function Determination Program," Revision 3 Surveillance Test Procedure (STP) 3.6.4.2-01, " Secondary Containment isolation Damper Closing Time Test," Revision 3 STP 3.5.1-05, "[High Pressure Coolant injection) HPCI System Operability Test,"

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b. Observations and Findinas On May 24,1999, the licensee determined that the "B" reactor recirculation pump mini-purge isolation valve, CV18048, failed to close during the conduct of STP 3.6.4.2-0 Maintenance card A43585 was initiated and the operating crew entered TS 3.6.1.3, Condition C, that required the affected ficw path to be isolated within 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> by use of at least one closed and de-activated automatic valve, closed manual valve, or blind flange. The valve was repaired and retumed to service within 16 hours1.851852e-4 days <br />0.00444 hours <br />2.645503e-5 weeks <br />6.088e-6 months <br /> after discovery i and the licensee exited the TS limiting condition for operation (LCO) condition. On May 26, upon further review by the shift technical advisor, it was determined that the operating crew should have entered TS 3.6.1.3, Condition A, that required the affected flow path be isolated within 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> after discovery, and if that condition was not met, within 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> the reactor was to be placed in a hot shutdown condition. Condition C applies to piping systems which penetrate the primary containment, but do not I

communicate with either the containment atmosphere or the primary containment system boundary. Condition A applies to piping systems which penetrate the primary containment and communicate with the containment atmosphere or the primary containment system boundary. The reactor recirculation pump mini-purge system communicates with the primary system boundary through the reactor recirculation pump seal, therefore, the more limiting Condition A should have been entered. The licensee de-activated the automatic valve and isolated the affected flowpath 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> after the valve was declared inoperabl Technical Specification 5.4.1.a requires, in part, that written procedures shall be implemented covering the activities recommended in Appendix A of Regulatory Guide 1.33, Revision 2, February 1978. Regulatory Guide 1.33 Revision 2, Appendix A, " Typical Procedures for Pressurized Water Reactors and Boiling Water Reactors," Section 1.h states, in part, that administrative procedures for log entries should be covered by written procedures. Administrative Control Procedure 1410.2, Revision 3, a procedure implemented by Section 15of Regulatory Guide 1.33, Step 3.3(1), requires that when any TS system or component is declared inoperable for reasons other than STPs, the appropriate LCO action shall be entered. Contrary to the ;

above, on May 24,1999, the licensee failed to implement Step 3.3(1) of ACP 1410.2, in l that the operations personnel entered TS 3.6.1.3.C. rather than the appropriate TS '

l LCO, TS 3.6.1.3.A., when the "B" reactor recirculation mini-purge isolation valve, CV1804B, failed to close and was declared inoperable. This Severity Level IV violation ,

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(50-331/99007-01(DRP))

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is being treated as a Non-Cited Violation consistent with Appendix C of the NRC Enforcement Policy. This violation is entered in the licensee's corrective as Action Request (AR) 1554 ~

On May 26,1999, the licensee conducted a fact finding meeting and determined that the operating crew entered the wrong TS due to ambiguous and misleading words used in the TS bases. Also, the operating crew relied on ACP 1410.7, which provided misleading information for CV1804B by not having an attemate isolation valve listed in the attached table. By listing an attemate isolation valve, this would have provided the necessary information for the operating crew to enter the more restrictive 4-hour LC Also, on June 23,1999, the inspectors identified that an operating crew failed to enter a more limiting LCO during the conduct of STP 3.5.1-05. The operating crew entered a 7-day LCO in accordance with TS 3.5.1, Condition B, when the residual heat removal torus cooling mode was initiated in support of the HPCI surveillance test. The operating crew entered a 14-day LCO in accordance with TS 3.5.1, Condition F, when HPCI was declared inoperable to support the surveillance testing. However, TS 3.5.1, Condition H, required that if the HPCI system was inoperable and one low pressure emergency core

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cooling system was inoperable, then a 72-hour LCO was to be entered to restore the HPCI system or the low pressure emergency core cooling system to an operable statu . After discussions with the NRC inspectors, the operations shift supervisor acknowledged that the more restrictive 72-hour TS LCO should have been entered during the HPCI operability test. The surveillance testing was completed and the HPCI system was declared operable the same day testing began, therefore, the proper TS LCO completion time was not exceeded. The inspectors, reviewed three previous HPCI system operability quarterly surveillance tests and found that in each case the more restrictive 72-hour TS LCO was entere . Conclusions -

On two' occasions operating crews did not enter the appropriate TS LCO. On May 24, 1999, the licensee entered the wrong LCO when a reactor recirculation mini-purge isolation valve failed to close and was declared inoperable. A Non-Cited Violation for failing to log the eppropriate LCO. Also, on June 23,1999, the inspectors identified that the proper 72-hour TS LCO was not entered for having a low pressure emerger.cy core cooling system and the high pressure coolant injection system inoperable during surveillance testin l 01.3 Observations of Plant Shutdown and Startuo for Reoairs to Containment Electrical Penetration Insoection Scone (71707)

The inspectors monitored portions of the startup and shutdown for the containment electrical penetration IJX105A. This included observation of portions of each operation ,

. shifts' activities, management and reactor engineering briefings, operator use of -

procedures, and coordination between control room and in-plant operators. The following integrated plant operating instructions were reviewed:

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IPOl 2,"Startup," Revision 57 f

l IPOI 3. " Power Operations (35% - 100% Rated Power)," Revision 41

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~ IPOI 4," Shutdown," Revision 44

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i Observations and Findinas f c ' On June 6,1999, operations personnel commenced a controlled shutdown in order for the licensee to repair shorted conductors in electrical containment penetration IJX105 Operations personnel performed an error-free shutdown. The inspectors observed good team-work between the various departments in planning the sequence of events to prepare, complete, and test the penetratio On June 14,1999, operations personnel commenced a plant startup after successful

. completion of post-maintenance testing of the electrical containment penetration. No other significant work was performed during the forced maintenance outage. Operators contended with one plant equipment issue during the startup. Operators secured from containment inerting due to the liquid nitrogen tank indicating zero percent leve Licensee troubleshooting determined that the tank level gauge was broken. The gauge was replaced and tank level was sufficient to continue inerting. However,24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> had elapsed since the operators had placed the mode switch in run. Since primary containment oxygen levels were not yet less than 4 percent, a 24-hour TS LCO was entered. Approximately 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> later, containment oxygen levels were less than 4 percent and the LCO was exited. The inspectors noted that the operators responded appropriately to the problem. No other significant equipment problems were noted during the startu I Conclusions

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The plant shutdown and startup in support of the forced outage for repairs to the primary '

- containment electrical penetration repairs were well controlled evolutions. Good teamwork was noted between the various licensee departments to support the maintenance activities. The shutdown to repair the penetration conductors )

' demonstrated a conservative plant operating philosoph Operational Status of Facilities and Equipment =

O2.1 General Plant Tours and System Walkdowns (71707)

The inspectors followed the guidance of Inspection Procedure 71707 in walking down accessible portions of the following system. The system chosen, based on maintenance

. work activities and probablistic risk significance, was:

. . High pressure coolantinjection Equipment operability, material condition, and housekeeping were acceptable in all cases.L The inspectors did not identify any substantive concems as a result of this walkdow l l

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08 Miscellaneous Operations issues (92901).  !

08.1 - (Closed) Licensee Event Report (LER) 50-331/97008-00: Momentaryloss of secondary containment during routine maintenance activity. This event was documented in

- Inspection Report 50-331/97010(DRP), which included licensee corrective actions. A Non-Cited Violation (50-331/97010-01) was issued. This item is close ,

0 (Cloried) LER 50-331/98008-00: Inoperable control building chiller due to potential loss of control air supply. On September 16,1998, the "A" control building chiller was declared inoperable due to a determination that a control valve was supplied by air from a nonsafety-related common line which if lost, would result in the valve failing closed and preventing chill water flow to the control building air conditioning unit. Specifically, the 20 pounds per square inch gauge (psig) heating and ventilation instrument air supply to.the control components for the cooling coil chill water control valve was fed by the common heating and ventilation instrument air supply.- This common air supply automatically isolated to protect the "A" and "B" side air supplies if a low pressure -

condition should occur. A loss of the common air supply equated to a loss of air to the control valve resulting in a cooling coil chill water control valve failing closed, thereby preventing chill water flow to the cooling coil of the control building air conditioning uni This configuration was recognized during an engineering review of air compressor loads 1 and requirements. The "B" chiller was not susceptible to this type of failure since its chill water control valve was supplied by the safety-related "B" heating and ventilation {

j instrument air compressor system, not the common suppl q A modification (Engineered Maintenance Action A48241) was performed to change

- the instrument air supply for the "A" cooling cdl chill water control valve from the

~ common supply to the safety-related "A" heating and ventilation instrument air compressor system. Technical Specification 3.7.5 required that with one control building chiller subsystem inoperable, that the subsystem be retumed to operable status within 30 days. The condition of the "A" control building chiller is believed to have existed since initial plant startup. Failure of the "A" control building chiller to meet the operability requirements of TS 3.7.5 was considered a  ;

violation (50-331/99007-01(DRP)). This Severity Level IV violation is being treated as a Non-Cited Violation consistent with Appendix C of the NRC Enforcement Policy. - The modification completed the corrective action necessary to address this issue. This item is close .3 (Closed) LER 50-331/99002-00: Surveillance declared not met due to a more restrictive interpretation of an unclear TS surveillance requirement. This event was documented in

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inspMian Report 50-331/99001(DRP), which included licensee corrective actions.' A Non-Cited Violation (50-331/99001-02) was issued. This item is close .4 (Closed) LER 50-331/99003-00: Entry into TS 3.0.3 due to inoperability of both trains of control room standby filter units (SFUs) caused by failure of a low differential pressure .

switch. On February 9,1999, during planned maintenance on the "A" train of the control room SFU, the low flow pressure differential switch indicating light went out. At the time, ,

the licensee believed this condition rendered the SFU inoperable. During efforts to l replace the bulb, maintenance technicians discovered that the same bulb on the "B" SFU was also not lit. The "B" SFU was declared inoperable, and with the "A" SFU

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inoperable for planned maintenance, TS 3.0.3 was entered. The operations shift commenced a plant shutdown .which was stopped at 80 percent power after the "B" SFU was repaired and TS 3.0.3 was exited.-

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.The cause of the event was the age-related failure of the bulb in the "B" SF Subsequent licensee review of the logic indicated that the bumed out bulb did not render the SFU inoperable. Discussion with the switch vendor indicated that an upgraded switch with sensors that have a longer service life was available. The .

- licensee ordered the upgraded switch to have in stock for future replacements. ,The

- inspectors noted that the licensee tock the appropriate TS required actions and made the proper notifications to the NRC. This item is close '

II. Maintenance

"M1 Conduct of Maintwnance 1 M1.1 General Comments Inspection Scoos (62707 and 61726) {

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The inspectors observed all or portions of the surveillance test activities and work request activities listed below. The applicable surveillance test or work package documentation was reviewed. Specific tests and work request activities observed are listed below:

MaintenancetAdLvities

. CMAR A43366- JX105A Containment electrical penetration; Move shorted circuit connections in header holes 17 and 23 to pretested spare conductors

. CMAR A44478 Fire pump test retum line throttle valve V33-0156; inspect / clean

. PMAR 1108887 Startup transformer 1X3; General inspection of transformer Surveillance of Activities

.- STP 3.5.1-05, "HPCI " System Operability Test," Revision 2

. STP 3.0.0-01, " Instrument Checks," Revision 12

. STP NS13B009, " Diesel Driven Fire Pump Operability Test," Revision 9 b'. Observations and Findings The inspectors noted that in general licensee personnel conducted the work associated with these activitios in a professional manner. Technicians were knowledgeable of their

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assigned tasks and work document requirements. Comments on specific items are

' detailed in the proceeding section M1.2 Primary Containment Electrical Penetration Conductors Shortina Insoection Scope (62707)

' The inspectors observed portions of maintenance and post-maintenance activities associated with primary containment electrical penetration IJX105A. Pre-job briefs, management update meetings, and post-job critiques were attended. The inspectors also reviewed the associated work order package A4336 Observations and Findinas on May 13,1999, a ground developed in the "A" residual heat removal logic. The 125VDC ground was found to involve position indication for MO-1908, shutdown cooling suction valve. The position indication fed the Group 4 logic and the residual heat removal pumps loss of suction path trip. The ground was determined to be inside '

penetration IJX105A. On May 17,' 1999, during main steam line isolation valve 1 functional testing, a partial actuation of the reactor protection system was not received when expected. ' Licensee troubleshooting determined that a short occurred on the reactor protection system sensor circuit for the "A" main steam line isolation valve -

position input. On the following day, troubleshooting determined that four circuits may be interconnected at or near the drywell penetration IJX105A. Another circuit determined to be affected was the "A" reactor recirculation pump runback logic. The pump could potentially run at full speed with the discharge valve closed. Also, there was a loss of the function to shift drywell cooling fans to high speed. On June 1,1999, the

"A" reactor recirculation pump low reactor building closed cooling water flow annunciator was alarming intermittently, but other indications did not support an actual low flow conditio '

Initially, the licensee addressed these problems by installing temporary modifications (see inspection Report 50-331/99005(DRS) for details). The licensee subsequently decided to shut down the plant on June 6,1999, to repair the shorted electrical conductors due to concems that the shorted conductors were in the same area within the drywell electrical penetration. The licensee planned to move the affected electrical conductors to spare conductors within the same penetration. Also, all electrical conductors in the affected area were relocated to another location within electrical penetration IJX105A. The work involved moving the bad / suspect conductors to pre-tested spare conductors. The work included approximately 184 splice de-terminations,262 conductor tests, and 158 splice re-terminations,12 of which were environmental qualification splices. Overall, the inspectors noted good attention to detail by the electrical technicians assigned to the work. The work order had sufficient detail to adequately perform the task. Also, management oversight was evident during the maintenance activitie . A wiring error was introduced during the post-maintenance testing portion of the job. An ,

. error was made on the electrical termination sheet. The individual preparing the '

termination sheet performed a field walkdown and identified four wiring discrepancies

and updated two of the four discrepancies.' The problem was missed during testing

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when the leads were lifted and the verifier did not specify the color of the lead to be

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lifted. When the lead was landed after the testing, the verifier specified the wire to land by color. At this point, the two technicians questioned themselves on the correct wires that they were going to land. . The technicians decided that the termination sheet was correct and landed the wires.' Due to the two wires being reversed,ihe recirculation pump motor-generator tripped on differential current when started. The inspectors attended the fact-finding meeting and considered the proposed corrective actions adequat Results of the testing revealed that there were seven shorted conductors altogethe None of the other conductors im'pacted safe operation of the plant. All other conductors satisfactorily passed th. ?esting. The testing results closely matched the electrical penetration 1JX105C testing in 1996, when eight conductors were found shorted and seven additional conductors were rejected based upon low resistence reading The licensee initiated actions to procure replacement electrical penetrations for the two discussed above and for two other similar penetrations. Two penetrations are

- scheduled for replacement in the upcoming refueling outage. The other two l penetrations were scheduled to be replaced in the following refueling outag Conclusions The repairs for the shorted conductors in the primary containment electrical penetration 1JX105A were well planned and executed. There was only one minor error due to lack of attention to detail introduced during planning and which was also missed during restoration of a conductor; however, the overall repair activities were completed satisfactoril . Engineering E1- Conduct of Engineering i E General Comments (37551)  ;

The inspectors evaluated engineering involvement in the resolution of emergent material condition problems and other routine activities. The inspectors reviewed areas such as

. operability evaluations, root cause analyses, safety committees, and self-assessment The effectiveness of the licensee's controls for the identification, resolution. and prevention of problems was also examine E1.2 . Fire Protection Valve Problems Inspection Scope (37551)

The inspectors reviewed the circumstances surrounding the replacement of the fire

- pump test retum line throttle valve, V33-0156. Interviews were conducted with L maintenance and engineering personnel. The following documents were reviewed:

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Engineered Maintenance Action (EMA) A40358 - V33-0156 Valve Replacement I

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Corrective Work Order (CWO) A43683 - Disassemble and Inspect Flow Blockage of

' V33-0156 EMA A43334 - Replace Cage for Newly installed Cage that was Plugging Observations and Findinos On August 5,1997, the licensee observed excessive vibration in the fire protection test retum line. The excessive vibration was caused by severe cavitation when throttling the fire protection test retum line control valve, V33-0156. Engineeing personnelinitiated and completed EMA A40358 to replace the ball valve with a cage valve to minimize the cavitation. On March 25,1999, the cage valve was installed and satisfactorily passed its

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post-maintenance test. On June 20,1999, the diesel driven fire pump was declared inoperable due to insufficient flow through V33-0156 during weekly surveillance testin . The insufficient flow was a result of debris plugging V33-0156. On June 23,1999, a modified cage valve was installed and post-tested satisfactorily to meet its operability condition; however, it was unable to satisfactorily meet the flow and pressure ranges for the fire pump test program. The inspectors reviewed EMA A40358 and noted several deficiencie The inspectors noted that the engineering evaluation for EMA A40358 lacked sufficient documentation to address the potential for valve plugging. The fire protection system and the general service water (GSW) system take a suction from the circulation water pit; therefore, the engineering evaluation compared the valve hole size (5/32 inch) to the GSW strainer hole size (1/16 inch). The evaluation noted that the GSW backwash system operated only on a high differential pressure. Therefore, the valve hole size was considered adequate. The inspectors identified that in addition to operating on high differential pressure, the GSW backwash system operated automatically every 8 hour9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br /> '

The high differential pressure was infrequently reached due to the timer activated backwash cycle. The er'gineering evaluation compared the valve cage hole size to the GSW strainer hole size and associated backwash system without complete i consideration for how the GSW strainer / backwash system operate J Also, EMA A40358 underestimated the amount and type of debris in the circulation

_pump water pit. The water source for the fire protection system was supplied from the

' cooling towers and the river water. The mechanical draft cooling towers are 25 years old and showing signs of wear. Plastic, wood fragments, and asbestos flakes from cooling tower louvers were found in the water. Also the diesel driven fire pump suction source is located in the comer of the circulation pump water pit where debris bettled due to stagnant water flow. The cooling tower screens and the diesel driven fire pump suction strainer hole sizes were both 7/8 inches, which was larger than the hole size for

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V33-0156. Therefore, although V33-0156 eliminated the cavitation problem, it acted as a strainer in the fire protection system. The inspectors noted that the engineering evaluation did not address these issues. Several meetings were held with licensee

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representatives to determine what data was used to support the adequacy of the replacement valv '

The licensee was working with the vendor to develop an adequate solution. The fire pump was considered to be operable based on meeting the weekly surveillance test flow

requirements. The licensee agreed that the engineering evaluation was insufficient and lacking detail and AR15894 was initiate !

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. Conclusions The engineering evaluation for the installation of the modified pump test retum line throttle valve, V33-0156, was deficient. The evaluation contained an incorrect description of how the general service water system strainer system operated. The amount and type of debris in the water was underestimated. The hole size for replacement valve V33-0156 was less than the strainer hole size for the pump and the cooling tower; therefore, V33 0156 acted as a strainer. Also, the engineering evaluation lacked adequate documentation to support its conclusion E8 Miscellaneous Engineering issues (92903)

E8.1 ' (Closed) Temoorarv instruction (TI) 2515/141. " Review of Year 2000 (Y2K) Readiness of Computer Systems at Nuclear Power Plants" a. - Insoection Scone (Tl2515/141)~

The purpose of the inspection was to review the licensee's Y2K program activities-designed to achieve Y2K readiness in accordance with Generic Letter (GL) 98-01 or GL 98-01 Supplement 1. The inspectors conducted a review of the licensee's Y2K activities and documentation, which included aspects of Y2K management planning, documentation, implementation planning, initial assessment, detailed assessment, remediation activities, Y2K testing and validation, notification activities, and contingency '

planning. Tt espectors used NEl/NUSMG 97-07, " Nuclear Utility Year 2000 Readiness,"u d NEl/NUSMG 98-07," Nuclear Utility Year 2000 Readiness Contingency.- The inspectors reviewed the following systems for potential impact of date-related processing problems in software or embedded components: engineered safety features systems, balance of plant system, radiation monitoring system, emergency notification system, plant process computer, and plant security syste ' Observations and Findinas

. Overall, the inspectors noted the licensee's program for Y2K plant readiness to be thorough. Documentation supporting systems testing was found to be acceptabl Conclusions The Y2K readiness review was completed with acceptable result E8.2 (Closed) Inspection Followuo item (IFI) 50-331/97014-02: High pressure coolant injection (HPCI) discharge pressure spikes during surveillance tests. On September 23, 1997, the inspectors observed, during the annual HPCI simulated automatic actuation surveillance test, that the discharge pressure gauge in the control room initially spiked high (above 1500 psig). The inspectors noted during previous HPCI tests that discharge

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_ pressure initially increased to approximately 1400 psig and then settled out at

. approximately 1200 psig. The inspectors observed that the pressure went off-scale on ,

the control room pressure gauge and questioned operations management and the {

system engineer following the test to determine if the system had been  !

over-pressurized. The system engineer reviewed the special monitoring traces that were routinely taken during HPCI tests and informed the inspectors that the peak pressure was approximately 1675 psig. Although this pressure was higher than the 4 13 l

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value used as an input in calculation 409-P80-331, Revision 2, the licensee was able to show that there was adequate margin to the stress limits and that there was no operability concem in this case. In calculation 409-P80-311, the engineer had assumed a peak pressure of 1590 psig, calculated the expected loads, and then determined the margin to the stress limits based on the loads. As a result of the inspectors' questions, the licensee identified the need to formally revise the calculation to use a higher peak pressure as an input valu Peak pressures up to 1675 psig occurred in the past; however, the calculation had not been revised and still assumed a peak pressure of 1590 psig. The licensee documented the occurrence on Action Request (AR) 971966 and planned to revise the calculation.~ However, the calculation was not revised. Instead the system engineer added a note to the piping class summary which stated that HPCI maximum service condition pressure may be exceeded for a short duration during HPCI system initiations and referred to AR 971966. In that AR, a calculation was performed that showed the piping still had approximately 20 percent margin at the increased pressure spike However, during the review of this issue the inspectors noted that the calculation had also considered occasional loads. This was overlooked in the initial review. A momentary spike of 6012 psig was calculated to be conservatively withstood by the pipin Also, during a March 1999 performance of the HPCI surveillance, the inspectors noted the same pressure spikes. The operators were unaware of the previous history of spiking problems with the HPCI surveillance tests. Subsequently, the licensee revised the HPCI procedures to include a note that explained the control room pressure gauge should be used for steady state indications only. The note also stated that the HPCI transient strip chart recorder should be used to determine any HPCI pump discharge pressure transient. This item is close E8.3 (Closed) LER 50-331/99001-00: Train of standby gas treatment (SBGT) system outside design basis due to loss of seismic qualification of a safety-related temperature

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transmitter caused by inadequate mounting bracket fasteners. On January 12,1999, a .

maintenance technician questioned the condition of fasteners used to support seismically qualified temperature transmitters on the "A" SBGT train. Engineering personnel inspected the fasteners and could not provide reasonable assurance of '

operability of the safety-related transmitters. The transmitters were declared inoperable, which resulted in the continued unavailability of the "A" SBGT train. The train was already in a 7-day LCO due to planned maintenance. The "A" SBGT train remained in the LCO until repairs were completed on January 14,1999, i

Also, the condition of the fasteners on the "B" SBGT train were immediately inspecte One missing fastener was found, but the engineers' evaluation determined the "B" SBGT train was still inoperable. The initial design of a number six screw threaded into the back of the control panel was replaced with threaded inserts and larger screws. The initial configuration was evaluated to have met seismic qualification, but lacked consideration for routine maintenance activities. The licensee appropriately followed TS LCO. The license made proper notifications of the issue to the NRC. This item is close ..

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IV. Plant Support 4 R1 Radiological Protection and Chemistry Controls-l R1.1 . Radiation Protection Personnel Respond to Contamination Solli in Reactor Buildina i

' Inspection Scooe f71750)

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l The inspectors assessed the response by radiation protection personnel to a contamination spill in the reactor building. The inspectors evaluated the licensee's response to the clean-up and reviewed Administrative Control Procedure (ACP) 1411.2,

" Control of Access to Radiological Areas," Revision 8. Survey and contamination wipes data were reviewe ~ ' Observations and Findinas -

On June 1,1999, the crack arrest verification system (located on the second floor of the reactor building) leaked radiologically contaminated water that became airbome and contaminated the first and second floors of the reactor building in excess of 1000 disintegrations per minute per centimeters squared. Upon discovery, the leak was isolated and the reactor building first and second floors were appropriately posted as contaminated areas in accordance with ACP 1411.2, " Control of Access to Radiological Areas." Radiation protection personnel restricted access to the floors and were effective in their decontamination efforts. Within several hours after discovery, the first and second floors of the reactor building were property decontaminated and the contamination postings were removed.' The effective response by radiation protection personnel minimized the potential of further spreading the contamination to additional ,

areas within the reactor buildin j l Conclusions The inspectors determined thaNadiation protection personnel appropriately restricted access to areas within the reactor building in response to a radiological contamination spill. The licensee was effective in its decontamination efforts, j

V. Management Meetings X Exit Meeting Summary The inspectors presented the inspection results to members of licensee management at the conclusion of the inspection on July 7,1999. The licensee acknowledged the findings presented. The inspectors asked the licensee whether any materials examined during tha inspection should be considered proprietary.- No proprietary information was identified.

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PARTIAL LIST OF PERSONS CONTACTED Licensee R. Anderson, Manager, Outage and Support J. Bjorseth, Maintenance Superintendent D. Curtland, Operations Manager J. Franz, Vice President Nuclear R. Hite, Manager, Radiation Protection M. McDermott, Manager, Engineering K. Peveler, Manager, Regulatory Performance G. Van Middlesworth, Plant Manager

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INSPECTION PROCEDURES USED IP 37551: Onsite Engineering-IP 61726: Surveillance Observation IP 62707: Maintenance Observation IP 71707:- Plant Operations IP 71750: Plant Support IP 92901: Followup - Operations IP 92902: Followup - Maintenance

- IP 92903: Followup - Engineering Tl 2515/141: Review of Year 2000 Readiness of Computer Systems at Nuclear Power Plants l

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ITEMS OPENED, CLOSED, AND DISCUSSED Opened 50-331/99007-01 NCV Failure to enter the proper TS LCO condition after declaring the PCIV inoperable 50-331/99007-02 NCV Failure of the control building chiller to meet TS operability requirements Closed 50-331/97008-00 LER Momentary loss of secondary containment during routine maintenance activity 50-331/97014-02 IFl HPCI discharge pressure spikes during surveillance tests 50-331/98008-00 LER inoperable control building chiller due to potential loss of control air supply 50-331/99001-00 LER Train of SBGT system outside design basis 50-331/99002-00 LER Surveillance declared not met 50-331/99003-00 LER Entry into TS 3.0.3 due to inoperability of both trains of control room SFUs caused by failure of a low differential pressure switch 50-331/99007-01 NCV Failure to enter the proper TS LCO condition after declaring the PCIV inoperable 50-331/99007-02 NCV Failure of the control building chiller to meet TS operability requirements Discussed Non I

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LIST OF ACRONYMS USED ACP Administrative Control Procedure -

AR Action Request DRP Division of Reactor Projects'

EMA Engineered Maintenance Action HPCI High pressure coolantinjection LCO Limiting Condition for Operation LER Licensee Event Report -

NCV Non-cited violation NEl Nuclear Energy Institute NRC Nuclear Regulatory Commission NUSMG Nuclear Utilities Software Management Group PSIG Pounds per square inch gauge SBGT Standby gas treatment system SFU Standby filter unit STP Surveillance Test Procedure TS Technical Specification Y2K -- Year 2000 I

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