IR 05000445/1999014

Insp Repts 50-445/99-14 & 50-446/99-14 on 990707-0821.Four Violations Occurred & Being Treated as Ncvs.Major Areas Inspected:Operations,Maint,Engineering & Plant Support

ML20212A782
Person / Time
Site:	Comanche Peak
Issue date:	09/14/1999
From:	NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION IV)
To:
Shared Package
ML20212A765	List: IR 05000445/1999014 ML20212A760
References
50-445-99-14, 50-446-99-14, NUDOCS 9909170129
Download: ML20212A782 (27)

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A ENCLOSURE U.S. NUCLEAR REGULATORY COMMISSION

REGION IV

Docket Nos.: 50-445 50-446 License Nos.: NPF-87 NPF-89 Report No.: 50-445/99-14 50-446/99-14 Licensee: TU Electric Facility: Comanche Peak Steam Electric Station, Units 1 and 2 Location: FM-56 Glen Rose, Texas Dates: July 7 through August 21,1999 Inspectors: Anthony T. Gody, Senior Resident inspector Scott C. Schwind, Resident inspector Neil O'Keefe, Senior Resident inspector Approved By: Joseph I. Tapia, Chief, Branch A ATTACHMENT: Supplemental Information

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9909170129 990914 PDR ADOCK 05000445 G PDR t

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EXECUTIVE SUMMARY Comanche Peak Steam Electric Station, Units 1 and 2 NRC Inspection Report No. 50-445/99-14; 50-446/99-14 INSPECTION PERIOD - 07/11 - 08/21/99 Operations

• The licensee successfully implemented new standard Technical Specifications on July 27,1999. All affected procedures were revised and available to operators upon the transition. The inspectors verified that all existing limiting conditions for operation remained in effect following the implementation (Section O3.1).

• Operators conducted themselves in accordance with procedures, training, and licensee management expectations. Communications were formal, clear, and concise and repeat-backs were observed to be enforced by everyone involved. Operators consistently reviewed alarm reference procedures when unexpected alarms were received. Operators scanned the control boards at the appropriate frequency and operators demonstrated a questioning attitude for unexpected indications. Operating logs were clear and concise. Entry into Technical Specification Limiting Conditions for Operation were properly documented and the duration was appropriately minimized )

through effective planning and scheduling (Section 04.1).

• The station service water system was in good material condition and capable of performing its designed functions. Housekeeping in the service water intake structure remained poor. All discrepancies noted by the inspectors during their walkdown had been previously identified by the licensee and entered into their corrective action program (Section O2.2).

Maintenance

• A number of examples were identified where nonplant equipment was stored inappropriately. One example involved two carts full of batteries secured to containment ;

radiation monitoring equipment conduits that were in violation of Station Administrative l Procedures. The licensee immediately corrected the problem and entered the condition in their corrective action program for trending (SmartForm SMF-1999-002079-00). This Severity Level IV violation is being treated as a noncited violation, consistent with Appendix C of the NRC Enforcement Policy (Section O2.1).

• Troubleshooting activities on the Unit 1 electrohydraulic control system resulted in a 140 MWe transient on the main turbine. The decision to reinstall a known failed component in an operating plant system for troubleshooting purposes was contrary to sound practices and resulted in the main turbine transient. The transient presented multiple complex challenges to control room operators and was a contributing factor in a failure of Unit 1 Main Feedwater Pump 1B. In addition, these failures occurred during peak grid loading, which necessitated operating Unit 1 with abnormal equipment conditions for 30 hours3.472222e-4 days <br />0.00833 hours <br />4.960317e-5 weeks <br />1.1415e-5 months <br /> while awaiting for grid conditions to support repair activities. (Section M2.1)

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Instrumentation and controls technicians demonstrated a questioning attitude by comparing a new speed sensing card with the old card prior to installation; however, a lack of adequate design documentation on the cards and incorrect drawings led to the installation of an incorrectly configured circuit card. This had no adverse impact on plant operations since the new card did not work (Section M2.1).

A licensee event report (LER 50-445;446/99002) was submitted for missing the Technical Specification surveillance requirement for steam generator gross activity composite determination on May 18,1999. The missed surveillance was caused by chemistry personnel overlooking the directions contained in Chemistry Shift Order The following day, the appropriate samples were taken and steam generator gross activity composite was found to be within specification. This condition was entered in the corrective action program (SmartForm SMF-1999-001339-00). The missed Technical Specification surveillance requirement is a Severity Level IV violation of plant Technical Specification 4.7.1.4 which is being treated as a noncited violation, consistent with Appendix C of the NRC Enforcement Policy (Section M8.1).

• The licensee experienced several rod control system failures and alarms on Unit 1 during this period and were partially successful at troubleshooting and eliminating the cause of the failures. Although Unit 1 control rods remained operable, the Unit 1 rod control system remained in manual at the end of the inspection period, which could present an added challenge to operators during plant transients. Because of high electrical demand and the need to ensure grid stability, troubleshooting plans were not fully implemented. This condition has been entered into the licensee's corrective action program (Section E2.1).

Enaineerina

• Several poorly implemented design modifications were identified during the fourth Unit 2 refueling outage. The first example involved the installation of expansion joints on steam generator atmospheric relief valves not qualified for the calculated pressure in the design modification. The second involved a nonconforming condition caused by a failure to remove shipping bars prior to the installation of several auxiliary feedwater system check valves. The shipping bar prevented the affected check valves from stroking to their full open position. The third example involved the installation of emergency core cooling throttle valves with the incorrect insert nozzle throat diamete Appropriate immediate corrective actions were taken and the specific root causes a ssociated with each issue were identified. Poor documentation of communications between vendors and engineering, inconsistent turnover between lead engineers, and tight vendor schedules were found to contribute to the problems. Inadequate work instructions contributed significantly to the installation of nonconforming auxiliary feedwater check valves in the plant. This condition was entered into the licensee's corrective action program (SmartForm SMF/PIR 1999-001103-01-00). This was a Severity Level IV violation of Technical Specification 6.8.1. This Severity Level IV vioiation is being treated as a noncited violation, consistent with Appendix C of the NRC Enf arcement Policy (Section E1.2).

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• The inspectors identified that the licensee implemented a design change to the controi room emergency pressurization system that did not conform to the ANSI /ASME Code N509-1976 requirement that the heat generated from radioactive decay and adsorption of iodine be considered when developing these setpoints. The failure to include appropriate design control measures in Design Change 12503, Revision 0, was a Severity Level IV violation of 10 CFR, Part 50, Appendix B, Section lil, " Design Control. This Severity Level IV violation is being treated as a noncited violation, consistent with Appendix C of the NRC Enforcement Policy. The licensee's immediate operability evaluation concluded that the design change error did not affect the radiation dose to operators for a postulated design bases accident. The licensee appropriately placed the issue in their corrective action program (SmartForm SMF-1999-001744-00)

(Section E4.1).

• The inspectors consulted with the NRC Office of Nuclear Reactor Regulation and concluded that the emergency core cooling system remained operable despite the nonconforming condition associated with throttle valve erosion. The licensee took adequate and timely corrective actions to address this condition. Although no violation of regulatory requirements was identified, the licensee failed to consider the degraded throttle valve issue in an operability evaluation associated with pressure locking of motor-operated valves. The licensee's failure to consider synergistic effects of multiple degraded conditions was a departure from past good performance (Section E8.2).

Plant Support

• The inspectors observed good radiological practices being implemented by plant personnel. Workers were familiar with their radiological work permit requirements. The inspectors accompanied licensee personnelinto the Unit 1 containment during power operations, observed good contamination controls, and maintained dose as low as is reasonably achievable (ALARA) (Section R1).

• The inspectors verified that plant fire protection equipment and systems were in good condition and generally available for immediate use. Combustible material was minimized and properly stowed in the plant (Section F2.1).

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Report Details Summary of Plant Status

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Unit 1 began the inspection period at 100 percent power. On July 30,1999, reactor power was reduced to approximately 80 percent following a main turbine transient caused by .

troubleshooting activities on the electrohydraulic control (EHC) system. On July 31, reactor power was decreased further to approximately 50 percent in order to repair the Unit 1 Main ]

Feedwater Pump 1B governor which mechanically bound during the transient. Unit 1 returned to 100 percent power on August 1. Unit 2 remained at 100 percent power throughout the inspection perio )

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1. Operations

01 Conduct of Operations 0 General Comments (71707)

Using inspection Procedure 71707, the inspectors conducted frequent reviews of ongoing plant operations. In general, the conduct of operations was found to be professional and safety-conscious; specific events and noteworthy observations are detailed in the sections below. Through daily observations of control room activities, the inspectors concluded that both units were operated by knowledgeable operators using good self-verification techniques and communication Operational Status of Facilities and Equipment O Plant Tours Inspection Scope (71707)

The inspectors conducted occasional tours of the facility to assess plant material condition, housekeeping, storage of nonplant equiprnent, and status of temporary modifications and to identify potential adverse conditions. Buildings and structures toured include: j

. Station service water intake structure

. Station service water tunnel .

. Units 1 and 2 safeguards buildings

. Units 1 and 2 contro room -

. Units 1 and 2 auxiliary building l

. Units 1 and 2 fuel handling buildings

. Units 1 and 2 electrical control building

. Units 1 and 2 turbine buildings '

. Unit 1 containment building Observations and Findinas While touring the auxiliary building on July 26, the inspectors observed an individual climbing in the overhead on the 810 foot elevation. The individual was not using a

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-5-ladder or a safety harness and was standing on cable trays. The individual stated that he was performing inspections of thermolag insulation in areas that could not be accessed by ladder. Furthermore, ho stated that it was acceptable to stand on cable trays since he was experienced and knew not to step on the center of the tray or areas that were not well supported. The inspectors were concerned that the practice of climbing on safety-related equipment could result in damage to the equipment and posed a personnel safety hazard when climbing occurred high in the overhead. This originally appeared to be an isolated example of this practice but, when it was discussed with the shift manager, he indicated that it was fairly typical for personnel to climb into the overhead without ladders. The inspector noted that, during similar thermolag inspections performed the next week in the auxiliary building, an individual inadvertently damaged a fire protection sprinkler head while climbing in the overhead. The sprinkler head damage resulted in approximately 500 gallons of water being sprayed into the building. There were no adverse affects on plant equipment, with the exception of a nearby security door card reader which was temporarily rendered inoperable due to water infiltration. The inspectors discussed these observations with licensee management who indicated that it was not feasible to adopt dJferent policies regarding the practice of climbing on safety-related equipment for the circumstances observe Many areas of the plant are only accessible by climbing onto safety-related equipmen The inspectors noted that management expectations for climbing on safety-related equipment were clear and understood by maintenance personne The inspectors observed an increasing number of examples where nonplant equipment was being temporarily stored or staged improperly. Most of the examples were minor in nature, not resulting in a violation of seismic interference or fire protection requirement For example, the inspectors occasionally noted unsecured ladders in ti.e plant adjacent to safety equipment. One particularly egregious example identified by the inspectors on July 26 involved two carts full of emergency lighting batteries staged for a containment entry planned for the following day. The inspectors found the heavily laden carts j secured directly to electrical conduit for containment radiation monitoring equipmen !

Station Administration Procedure 661,"Non-Plant Equipment Storage and Use inside j Seismic Category I Structures," requires specific securing methods to prevent seismic

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interaction with safety-related plant equipment. When informed by the inspectors, the licensee immediately corrected the issue. This Severity Level IV violation (50-445/9914-01)is being treated as a noncited violation, consistent with Appendix C of the NRC Enforcement Policy. This violation is in the licensee's corrective action program as SmartForm SMF-1999-002079-0 The inspector accompanied licensee personnel into the Unit 1 containment building during a routine entry at power. Material condition and cleanliness were generally goo j However, the inspector observed several plastic equipment labels attached with adhesive that had fallen on the floor. Radiation protection technicians removed the tags from containment and initiated a SmartForm to evaluate the condition. There was no immediate concern for sump clogging potential since the loose tags were removed from containment. All equipment staged inside containment was properly secured and did not interfere with any safety-related equipment, with perhaps the exception of scaffolding permanently stored inside containment for outage use. The inspector observed that the scaffolding storage racks located on the 808 foot elevation were in

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-6-close proximity to the containment liner. The racks were otherwise secured to prevent movement during a seismic event. When questioned about this, the licensee stated that, due to the relative masses of the scaffolding racks and the containment wall, and the fact that any collision between the racks and the wall during a seismic event would only result in compressive loading of the containment liner, there was little concern for puncturing the liner during a seismic event. However, the licensee also stated that this was not good practice as movement of the racks could cause damage to the liner coating. The licensee verified that the air gap was sufficient to preclude containment I liner damag ) Conclusions A number of examples were identified where nonplant equipment was stored inappropriately. One example involved two carts full of batteries secured to containment radiation monitoring equipment conduits that were in violation of Station Administrative Procedures. The licensee immediately corrected the problem and entered the condition in their corrective action program for trending (SmartForm SMF-1999-002079 00). This Severity Level IV violation is being treated as a noncited violation, consistent with Appendix C of the NRC Enforcement Polic .2 Station Service Water System Walkdown Insoection Scope (71707)

Using inspection Procedure 71707, the inspectors performed a walkdown of the engineered safety features portions of the station service water syste Observations and Findinas The inspectors conducted a walkdown of the major system components in the station service water system. This inspection included a walkdown of the station service water intake structure and the service water tunnel leading into the auxiliary buildin The service water tunnel was recently refurbished and was in good condition. There were no signs of corrosion on any of the service water piping or pipe support However, there was enensive general corrosion on the base plates for the pipe supports. This was due to approximately one inch of water standing on the floor of the tunnel. The licensee had previously identified this condition and determined that the water was seepage from ground water. There is a shallow well adjacent to the service water tunnel equipped with dewatering pumps for the purpose of lowering the water table in the area where the service water headers penetrate the tunnel wall, but the licensee has experienced repetitive failures of the pumps, which has resulted in the seepage around the wall penetrations. This condition has been entered into the licensee's corrective action program and has been addressed in the buildings and structures system health report. The licensee intends to correct the problem of ground water infiltration prior to completing the service water tunnel refurbishment work on the pipe support base plate o

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The inspector toured the service water intake structure. The licensee has had difficulty l maintaining cleanliness and accessibility in this area due to the large number of spiders that breed in the building. There have been numerous attempts at eliminating the spiders, including the use of various insecticides and a recent modification to allow the lights to be switched off while the building is not occupied. The intent of this modification was to decrease the number of flying insects in the building, thereby decreasing the food supply for the spiders. The modification was only partially successful. Most recently, the licensee has sprayed the building with an insecticide that has a residual killing effect, which appeared to have been effective in that the inspector noted no active spiders in the building. Cleanliness and general housekeeping of this area remained poor due to the insect debris. The material condition of equipment in the building was difficult to assess due to the poor cleanliness. The licensee has developed an additional modification to install screens underneath the gratings in the service water bays. The intent is to further restrict the infiltration of flying insects into the buildin This condition has been entered into the licensee's corrective action program and has been documented in the buildings and structures system health repor Conclusions The station service water system was in good material condition and capable of performing its designed functions. Housekeeping in the service water intake structure ,

l remained poor. All discrepancies noted by the inspectors during their walkdown had l been previously identified by the licensee and entered into their corrective action progra O3 Operations Procedures and Documentation

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03.1 Implementation of the New Standard Technical Specifications Insoection Scoce (71707)

The inspectors observed the licensee prepare for and implement the new standard Technical Specifications. Existing tracking limiting conditions for operation and emergent active limiting conditions for operation were reviewe Observations and Findinas On July 27, the licensee implemented the new standard Technical Specifications. In addition to extensive operator training, the inspectors observed that, for several weeks prior to the implementation date, control room operators maintained a parallel set of logs for tracking entry into limiting conditions for operation per the new standard Technical Specifications. This was done to acclimate the control room staff to the use of the new

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specifications. On the date of the transition, the licensee had staged a complete set of revised operations procedures for both units in the control room. The inspectors verified that the licensee appropriately transferred all existing limiting conditions for operations log entries to the new log.

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! Conclusions

! The licensee successfully implemented new standard Technical Specifications on July 27,1999. All affected procedures were revised and available to operators upon the transition. The inspectors verified that all existing limiting conditions for operations ,

remained in effect following the implementatio I i 04 Operator Knowledge and Performance l 1 04.1 Control Room Operator Performance Inspection Scope (71707. 92901)

The inspectors conducted periodic tours of the control room to observe routine operator i

performance and discussed specific performance observations with operators and licensee management. Operator response to several plant transients were reviewe Challenges, limitations, and equipment problems associated with those transients were I discussed with the operators involved in those transient Observations and Findinas in general, the inspectors observed operators conduct themselves in accordance with procedures, training. and licensee management expectations. Communications were ~

formal, clear, and concise and repeat-backs were observed to be enforced by everyone involved. Operators consistently reviewed alarm reference procedures when unexpected alarms were received. Operators scanned the control boards at the

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appropriate frequency and operators demonstrated a questioning attitude with unexpected indications. Operating logs were clear and concise. Entry into Technical Specification Limiting Conditions for Operation were properly documented and the duration was appropriately minimized through effective planning and schedulin On August 2, while performing a channel operability test on the Unit 2 Steam Generator narrow range level Loop 2-L-0539, the instrumentation and controls technician arm slipped, inadvertently placing Loops 2-P-0505,2-P-0514, and 2-P-0524 in test also.

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This caused a loss of indication and control response associated with 2-PT-0505 (first J stage turbine impulse pressure),2-PT-0514 (Main Steam Line 1 pressure), and 2-PT-0524 (Main Steam Line 2 pressure), all failing low. Control rods automatically inserted because reference reactor coolant temperature failed low. Main feedwater pumps slowed down and feedwater regulating valves for Steam Generators 1 and 2 started to close because of the loss of steam flow signal. Operators responded quickly by diagnosing the cause of the rod insertion and appropriately placed the rod control i L system in manual. Flow deviations and failed instrument channels for Steam I

i Generators 1 and 2 were noted. Operators appropriately placed feedwater regulating

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valves in manual and restored flow to Steam Generators 1 and 2. Main feedwater pump speed was observed to be decreasing and the main feedwater pump master controller was placed in manual. Feedwater pump speed was restored. Operators also recognized that the steam dumps had a 100 percent demand signal from the failed first L

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. stage impulse pressure and appropriately minimized the plant transient during the restoration, avoiding the C-7 arming signal which, if actuated, would have resulted in a plant trip and a safety injection. The inspectors noted that the transient was responded to in a rapid but orderly and controlled fashion. The lowest steam generator level recorded was approximately 48 percent and the lowest recorded pressurizer pressure was 2203 psig. Although operators are trained on similar scenarios, this particular combination of failures had never been part of operator training. The inspector found that operators used their training and knowiedge of the plant to diagnose each problem and take prompt and effective corrective actions to limit the impact on continued plant l operation On August 3, the reactor operator noted that the Steam Generator 1-01 feedwater l'

regulating valve was closed slightly more than normal. Steam Generator 1-01 level had not yet changed significantly.. The feedwater regulating valve was placed in manual and the abnormal operating procedure was referenced. After the alternate controlling ,

channel was selected, the feedwater regulating valve was restored to automatic operation. Troubleshooting revealed a failed NMD circuit card in the steam generator ,

water level control system. The inspector found that the operator demonstrated '

l attentiveness to the control boards and took the appropriate actions for a failed instrument, Conclusions Operators conducted themselves in accordance with procedures, training, and licensee management expectations. Communications were formal, clear, and concise and repeat-backs were observed to be enforced by everyone involved. Operators consistently reviewed alarm reference procedures when unexpected alarms were received. Operators scanned the control boards at the appropriate frequency and operators demonstrated a questioning attitude for unexpected indications. Operating logs were clear and concise. Entry into Technical Specification Limiting Conditions for Operation were properly documented and the duration was appropriately minimized through effective planning and schedulin II. Maintenance M1 Conduct of Maintenance M1.1 General Observations (61726, 62707)

The inspectors conducted inspections of routine maintenance and surveillance activities I using Inspection Procedures 61726 and 62707. In general, the conduct of maintenance and surveillance was professional and safety consciou o-

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-10-M1.2 Maintenance and Surveillance Observations insoection Scope (61726. 62707)

The inspectors observed the conduct of both plant surveillance and maintenance darin;;

the report period. The inspectors observed all or portions of the following activities:

. Unit 2, Train A, diesel generator operability test

. Unit 2 turbine-driven auxiliary feedwater pump test

- Unit 2 core flux map Observations and Findinas in general, the inspectors found that the licensee conducted maintenance ed surveillance activities in accordance with plant procedures. Specific observatens are discussed belo The inspectors observed the performance of the monthly operability test on the Ur.n 2, Train A diesel generator. There was some confusion on the part of the plant equipment operator as to how to reset one of the emergency diesel trip switches after exercising '.c during startup preparations. This is a pneumatic plunger-type switch which is in series and downstream of another emergency diesel trip switch. The system engineer was present and explained that, due to buildup of air pressure on the fuel rack trip actuator, the upstream trip switch had to be cycled in order to reset the downstream switch. This

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was done and both switches were successfully reset. The inspectors observed the engine start and performed a walkdown of ti:9 engine while it was running. The engine started and the generator was ready for loading within the required 10 seconds. The inspectors noted one small water leak in the jacket water cooling piping and one small oil leak on the lube oil coole The inspectors observed performance of the quarterly surveillance test of the turbine-driven auxiliary feedwater pump in Unit 1 per Procedure OPT-206A, Revision 1 Operators, maintenance personnel, and the system engineer attended a detailed briefing prior to starting the test. The inspectors observed that the system had some minor material condition problems. The pump had a 60 drop per minute packir g leak at both ends. Tha turbine had a notable gland leak -on the turbine end which leaked steam into the relaCvely small, unventilated room. The pump room got hot and steamy qudly, with significant condensation observed to form on equipment. The inspector discussed the condensation observation with the system engineer and operations personnel, who stated the condition had existed for quite some time, but that a major overhaul of the ,

turbine-driven auxiliary feedwater pump was planned for the upcoming fall refueling ;

outage. The inspectors noted that system engineering had already appropriately '

reviewed the environmental conditions in the room and concluded that the excessive steam and heat was not sufficient to exceed equipment environmental qualification !

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-11-M2 Maintenance and Material Condition of Facilities and Equipment M2.1 Unit 1 EHC System Troubleshootina and Main Turbine Transient Insoection Scope The inspector reviewed the licensee's troubleshooting activities on the Unit i electrohydraulic control system which resulted in a main turbine transien Observations and Findinas On July 30, an EHC system failure alarm was received in the control room. Operators took the appropriate actions per the alarm response procedure and determined that channel one of the speed sensing circuit had failed. There are two channels of speed sensing in the EHC system. Channel one is the default channel and the system will automatically shift to channel two upon f ailure of channel one. Instrument and control technicians were notified and located a replacement circuit card for channel on However, technicians noted that the replacement card did not match the installed car ;

The new card was verified against circuit diagrams to be correct for the application and the decision was made to install it in the system. After installation, the EHC system did not shift speed sensing back to channel one, indicating that the new card was not functioning as expecte In order to further troubleshoot the system, the technicians placed the failed card back in the system in order to take voltage readings on it. They did so with the card output jumper removed. believing that this would prevent any faults on the card from affecting the channel two card output. Immediately after the card had been installed, it began functioning again and the EHC system shifted speed sensing back to cnannel one. With the output jumper for channel one removed, there was no speed signal to the EHC system, which caused main turbine control valves to go full open. The technicians saw that the card was functioning properly and continued with the installation by connecting the output jumper, which resulted in a 140 MWe main generator transient. With the speed signal restored, main turbine load stabilized but the transient resulted in extraction steam to Feedwater Heater 3A isolating and the governor valve for Main Feedwater Pump 1B mechanically binding. Technicians believed that the original failure mechanism for the card was heat-related and that, prior to reinstallation, the card had cooled sufficiently to function agai Further investigation revealed that the new speed sensing card, which had been obtained from the warehouse, had been configured for a 3600 rotations per minute (rpm) turbine rather than the licensee's 1800 rpm turbines. Furthermore, the circuit diagram used to verify the card also reflected the 3600 rpm configuration. The new card was reconfigured for the 1800 rpm application and installed later that evenin An approximate 3 MWe load swing was expected during this evolution; however, when

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-12-the new card was installed, the plant experienced an approximate 25 MWe loss of loa This caused a minor feed system transient but, afterward, the new card appeared to function properly. The licensee was unsure as to the cause of the larger than expected transien Conclusions Troubleshooting activities on the Unit 1 EHC system resulted in a 140 MWe transient on the main turbine. The decision to reinstall a known failed component in an operating plant system for troubleshooting purposes was contrary to sound practices and resulted in the main turbine transient. The transient presented multiple complex challenges to control room operators and was a contributing factor in a failure of Unit 1 Main Feedwater Pump 18. In addition, these failures occurred during peak grid loading, which necessitated operating Unit 1 with abnormal equipment conditions for 30 hours3.472222e-4 days <br />0.00833 hours <br />4.960317e-5 weeks <br />1.1415e-5 months <br /> while awaiting grid conditions to support repair activitie Instrumentation and controls technicians demonstrated a questioning attitude by comparing a new speed sensing card with the old card prior to installation; however, a ,

lack of adequate design documentation on the cards and incorrect drawings led to the installation of an incorrectly configured circuit card. This had no adverse impact on plant operations since the new card did r,ot wor M8 Miscellaneous Maintenance issues M8.1 (Closed) Licensee Event Report (LER) 50-445:446/99002: missed Technical Specification surveillance for steam generator gross activity composite determinatio Technical Specification 4.7.1.4 and Technical Specification Table 4.7-1 requires gross activity sampling of the secondary system at least once per 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br />. Once the missed surveillance was identified on May 18, the missed surveillance activities were conducted and a SmartForm was written. The licensee appropriately classified the missed surveillance as a plant incident and appropriately submitted an LER on June 1 The licensee's completed plant incident report concluded that the chemistry personnel overlooked the directions contained in Chemistry Shift Orders. Several contributing factors were identified such as: (1) the normal shift compliment of three chemistry technicians was reduced to two, (2) shift turnover may have been too informal and shift turnover sheets did not specifically require technicians to address Technical Specification activities to be completed on their shift, (3) although management was aware of the reduced shift compliment of chemistry technicians the previous night, no verification of activities completed was performed, (4) the day shift lead chemistry technician could not get access to the database the following day because of man-machine interface problem The missed Technical Specification surveillance requirement was a Severity Level IV violation of plant Technical Specifications (50-445;446/9914-02). This Severity Level IV

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-13-violation is being treated as a noncited violation, consistent with Appendix C of the NRC Enforcement Policy. This violation is in the licensee's corrective action program as SmartForm SMF-1999-001339-00-0 M8.2 (Closed) LER 50-445/99003: Unit 1 battery surveillance requirements not performed with the proper periodicity as required by Technical Specification 4.8.2.1.e. This issue was treated as a noncited Severity Level IV violation in NRC Inspection Report 50-445;446/99-10. No further issues were identified during the inspector's review of the LE Ill. Enaineerina E1 Conduct of Engineering E General Comments (37551. 92902)

Routine and emergent engineering activities were inspected in accordance with Inspection Procedures 37551 and 92902. In general, the inspectors found engineering performance atypical. Engineers demonstrated a lack of rigor and formality during several design modifications discussed below. Nevertheless, engineering activities generally met the minimum standards with only one notable exception discussed below where instructions were not adequately translated into maintenance procedures for installing new check valve E1.2 Inadvertent Installation of Nonconformina Components Inspection Scope (37551. 92902)

The inspectors reviewed the licensees corrective actions following a series of issues associated with the installation of nonconforming components in the plant during the fourth Unit 2 refueling outage. Although other less-significant examples were identified by the licensee, the three more-significant examples were reviewed by the inspectors and are discussed below. The first example involved the installation of expansion joints on steam generator atmospheric relief valves not qualified for the calculated pressure in the design modification. The second involved a nonconforming condition caused by a failure to remove shipping bars prior to the installation of several auxiliary feedwater system check valves. The shipping bar prevented the affected check valves from stroking to their full open position. The third example involved the installation of emergency core cooling (ECCS) throttle valves with the incorrect insert nozzle throat diamete Observations and Findinas Because the licensee experienced a number of vendor equipment issues during the spring 1999 fourth Unit 2 refueling outage, a task team was formed to evaluate each issue, identify the cause, and make recommendations on broad or cross-cutting findings to prevent the same issues from occurring again in the future. Some of the specific problems are discussed in more detail below:

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-14-Steam Generator Atmospheric Relief Valves The licensee's engineering department began working on steam generator atmospheric relief valve (ARV) modifications in 1990. Excessive vibration, noise, and erosion resulted in occasional valve leakage and required frequent valve readjustment. Design Modifications (DM)91-177 and 93-60 were initiated for Units 1 and Unit 2, respectivel ,

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A valve vendor, Control Components, Inc. (CCl), was contacted for an improved design which included new drag velocity control trim to improve valve control and to reduce vibration and noise. CCI recommended that a silencer be installed to increase ARV i

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back pressure which would reduce vibration and noise and improve control issues. In 1994, the licensee decided to have CCI include the silencers in the design. DM 91-177 for Unit 1 was completed, reviewed, and approved in December 1994. During the final review of DM 93-60 for Unit 2, in 1997, an issue which could have challenged the environmental qualification of components in the steam penetration rooms was found by the licensee. The silencer apparently increased the ARV discharge pressure sufficiently to result in steam coming from the ARV tailpipe venturi rather than air being sucked into it. Later in 1997, the licensee contacted the Gibbs and Hill Company engineer who designed the vent stack piping to discuss options. The engineer from Gibbs and Hill recommended the installation of an expansion joint to eliminate the pressure problem and reportedly estimated the required expansion joint pressure rating to be about 15 psig. Without further analysis, a third vendor was contacted to provide expansion joints rated for 15 psig. After installation of the new design but before it had been placed in service, CCI found that the expansion joints were not qualified for the ,

calculated pressure in the design modification. The expansion joints were subsequently l removed prior to placing the equipment in servic l The licensee's pant incident report (SmartForm SMF/PIR-1999-000762-01-00) identified the root causes as follows: (1) engineering initially failed to recognize that Calculation 16345-ME(B)-051, Revision 2, which verifies that the vent stack designs for main steam safety and relief valves are sufficient to prevent steam blowback at the vent stack, was impacted by the DM, and (2) engineering failed to verify the adequacy of the design l l

input of 15 psig for the expansion joint prior to issuing the design specification to the vendor. The task team, which evaluated generic implications, found that the issues were caused primarily by multiple modification leaders, vendor errors, and poor or no documentation of communication between engineering and the vendors. The inspectors noted that no violation of requirements occurred because the nonconforming condition j was identified and removed prior to returning the equipment to service. The inspectors noted that the plant incident report corrective actions had not yet been implemente Since the ARV modification was planned for the upcoming Unit 1 refueling outage, the ,

inspector questioned the licensee's actions to prevent the same errors from occurrin l The licensee indicated that they had changed DM 91-177 to eliminate both the silencer and expansion joint. The inspector found the short-term corrective actions adequat Auxiliary Feedwater System Check Valves On April 19, while performing a feedwater ASME Code Section XI check valve surveillance test, lower than expected flow rates were observed from the turbine-driven

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-15-auxiliary feedwater pump supply to Steam Generator 2-04. Subsequent visual inspection of Valve 2AF-0106 revealed that a shipping bar installed by the vendor to prevent damage during shipping was still installed in the valve. The licensee developed an aggressive plan to inspect the remaining check valves and found an additional shipping restraint installed in motor-driven auxiliary feedwater pump to Steam Generator 2-03, Valve 2AF-0093. Both restraints were removed and the valves were returned to senic Auxiliary feedwater check Valves 2AF-0106 and 2AF-0093 were replaced with a new style check valve during the third Unit 2 refueling outage (2RF03). The old style Borg/ Warner swing check valves were replaced with a new nozzle check valve made by Mokveld Valves, Inc. and purchased from Hayward Tyler, Inc. The old valves were replaced because of inconsistent performance during low pressure operation. The new nozzle check valves used a spring-loaded disc / rod assembly to improve closure characteristics. A total of seven of this type of valve had been installed on Unit 2 and four were installed on Unit 1, all were inspected. Valves 2AF-0103 and 2AF-0093 were I installed on November 11 and 20,1997, respectively. The postmaintenance testing of I these valves did not identify the problem because the test pressure was high enough to cause the retaining device to bend, allowing the required flow at high differential pressures to be passe The inspector was concerned that the postmaintenance test was not adequate. The ,

inspector found that the sunteillance testing met the ASME Section XI Code full stroke l test requirements by testing the check valve's capability to pass minimum accident flow conditions. No violation of ASME Section XI was identified. The operability and reportability reviews conducted by the licensee concluded that the auxiliary feedwater system remained operable and the nonconforming condition was not reportable. The inspector reviewed the licensee's technical evaluation and found that it contained sufficient rigor and detail to demonstrate that the auxiliary feedwater system was capable of delivering the required accident flowrates. The licensee appropriately assumed the worst case condition of a pipe break on the highest flow-rate steam generator in their calculatio The licensees plant incident report (SmartForm SMF/PIR-1999-001103-01-00) identified the causes as follows: (1) the vendor omitted relevant information regarding the need to remove shipping restraints prior to installation, (2) maintenance workers were not familiar with the operating characteristics of the new check valves, (3) maintenance procedures did not require a verification of check valve freedom of motion prior to installing, and (4) postmaintenance testing did not identify the issue. The task team report attributed the issue to poor vendor communication of shipping restraints and maintenance not familiar with the new design. The inspector recalled that, during ,

conference calls with the vendor, the vendor had indicated that the shipping restraints I

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were installed at the licensee's request. Even though they interviewed all personnel involved and reviewed all documentation, the task team could not confirm that the licensee had developed this new requirement to install a shipping restraint on the check valve I

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-16-The inspector noted that inadequate work instructions contributed significantly to the installation of a nonconforming component in the plant. This was a violation of Technical Specification 6.8.1 which requires, in part, that procedures and instructions be developed in accordance with NRC Regulatory Guide 1.33," Quality Assurance Program Requirements." Regulatory Guide 1.33, Appendix A, Section 9, requires that procedures for performing maintenance be properly preplanned and performe Contrary to these requirements, the maintenance activity to install new auxiliary feedwater check valves was not properly preplanned and performed for Valves 2AF-0106 and 2AF-0093, which resulted in the installation of a nonconforming conditio This was a Severity Level IV violation (50-446/9914-03) of Technical Specification 6. This Severity Level IV violation is being treated as a noncited violation, consistent with Appendix C of the NRC Enforcement Policy. This violation is in the licensee's corrective action program as SmartForm SMF/PIR-1999-001103-01-0 ECCS Throttle Valves During postmodification testing of hot leg safety injection ECCS Valves 2SI-8816A, B, C, and D, the licensee identified that they could not achieve the minimum ECCS flow rates specified in the surveillance test even with the throttle valve fully open. The subsequent investigation revealed that the insert nozzle throat diameter was 0.60 inches rather than the design value and procured specification of 0.75 inches. An engineering safety evaluation subsequently concluded that the as-left ECCS flow rates were acceptabl The inspector reviewed the licensee's safety evaluation and operability evaluation and concluded that it contained sufficient engineering rigor and detail to demonstrate immediate operability. The licensees plant incident report (SmartForm SMF/PIR-1999-000992-01-00) appropriately documented a Mode 4 restraint until a detailed calculation could be performed. The detailed ECCS calculation conducted by the Westinghouse corporation concluded that the analyzed minimum accident ECCS flow rates would still be met with the new configuration. The inspector could find no reason to challenge this conclusio The hcensee concluded in their plant incident report that no failure or weak barriers were identified that were within managements control. The root cause was attributed to vendor personnel error. It appeared that the vendor machinist misread the drawings and machined the insert nozzle to 0.60 inches rather than 0.75 inches. No corrective actions were required by the plant incident report. The licensee's task team report noted that the cause was attributed to a vendor personnel error, and the fact that the actual valves were not tested was a missed barrier. The inspector found the licensee's acceptance of one verification barrier for an 10 CFR, Part 50, Appendix B, supplier a departuro from their typically conservative business approach. Nevertheless, the inspector found that the licensee met the 10 CFR, Part 50, Appendix B requirement to verify adequacy of design by conducting thorough postmodification testing which appropriately identified and evaluated the issue prior to placing the nonconforming condition in service. Therefore, no violation of NRC requirements was identifie .

-17- Conclusions Several poorly implemented design modifications were identified during the fourth Unit 2 refueling outage. The first example involved the installation of expansion joints on

' steam generator atmospheric relief valves not qualified for the calculated pressure in the design modification. The second involved a nonconforming condition caused by a failure to remove shipping bars prior to the installation of several auxiliary feedwater system check valves. The shipping bar prevented the affected check valves from stroking to their full open position. The third example involved the installation of ECCS throttle valves with the incorrect insert nozzle throat diameter. Appropriate immediate corrective actions were taken and the specific root causes associated with each issue were identified. Poor documentation of communications between vendors and engineering, inconsistent turnover between lead engineers, and tight vendor schedules were found to contribute to the problems. Inadequate work instructions contributed significantly to the installation of nonconforming auxiliary feedwater check valves in the plant. This condition was entered into the licensee's corrective action program (SMF/PIR 1999-001103-01-00). This was a Severity Level IV violation of Technical l Specification 6.8.1. This Severity Level IV violation is being treated as a noncited i violation, consistent with Appendix C of the NRC Enforcement Polic !

E2 Engineering Support of Facilities and Equipment l

E2.1 ~ Unit 1 Rod Control System Failures and Troubleshootina Insoection Scope (37551)

The inspector observed the licensee's troubleshooting activities regarding several failures and alarms in the rod control syste Observations and Findinas While reducing Unit 1 reactor power in order to troubleshoot the governor on Main Feedwater Pump 1B, control room operators received an urgent rod control failure alarm on Rod Control Power Cabinet 2AC. This occurred while inserting control rods with Control Banks B and C overlapping. Initial troubleshooting of Rod Control Power ,

Cabinet 2AC indicated a multiplexer relay was loose. The relay was reseated in its I

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socket and the alarm was reset. However, operators received an identical urgent failure alarm while attempting to insert rods with Control Banks B and C overlapping. As a result, operators took manual control of the rods and restored them to their original position in order to stabilize the plant. Additional troubleshooting activities included replacement of the multiplexer and measurements on the output of the rod control power supplies and thyristors. These neither corrected the problem nor revealed the cause of the failure. The licensee developed a troubleshooting plan to further investigate this condition. Implementation of the plan was delayed due to the need to maintain plant reliability and because of the high demand for power associated with the extremely hot summer month E

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-18-On August 5, control room operators received an urgent failure alarm on Unit 1 Rod Control Power Cabinet 2BD with no rod motion. The licensee was unable to determine the cause of the alarm; therefore, rod control was placed in manual. On August 12, a nonurgent failure alarm was received on the same power supply cabinet. At this time, the licensee was able to determine that a 24 volt power supply in the cabinet was failin The power supply was replaced on August 14, which appeared to have corrected this conditio On August 5, a nonurgent failure alarm was received on the rod control logic cabine This was attributed to the failure of a 16 volt power supply. The power supply was replaced on August 14 in conjunction with the 24 volt power supply in Cabinet 2B During this activity, the pulse-to-analog converter for Control Bank B failed, causing group position indication on the main control board for that group to indicate zero. This was later attributed to heat buildup in the pulse-to-analog converter during the maintenance when the logic cabinet doors were open. This allowed the normal cooling air flow path through the cabinet to be short-circuited, causing an increase in temperature inside the cabinet where the normal air flow was reduced. The condition cleared after the doors were closed and temperature returned to normal inside the cabinet, Conclusions The licensee experienced several rod control system failures and alarms on Unit 1 during this period and were partially successful at troubleshooting and eliminating the cause of the failures. Although Unit 1 control rods remained operable, the Unit 1 rod control system remained in manual at the end of the inspection period, which could present an added challenge to operators during plant transients. Because of high electrical demand and the need to ensure grid stability, troubleshooting plans were not fully implemented. This condition has been entered into the licensee's corrective action progra E4 Engineering Staff Knowledge and Performance i E4.1 Control Room Emeroency Pressurization Unit Deslan Chanae ,

l Inspection Scoce (37551)

The inspector reviewed a design change notice that changed the setpoints for the control room emergency pressurization unit temperature switches, observed the modification implemented and postmodification testing on Train A, and reviewed the postmodification test result Observations and Findinas Plant Technical Specification 3.7.7 requires that both control room emergency filtration / pressurization system trains be operable in all operating modes and when irradiated fuel is being moved. Every 31 days, the operation of each train is verified by

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-19-operating them for a minimum of 10 hours1.157407e-4 days <br />0.00278 hours <br />1.653439e-5 weeks <br />3.805e-6 months <br /> with the heaters on. The heaters are needed to prevent humidity from decreasing the effectiveness of the charcoal beds and are designed to limit the maximum temperature of the charcoal beds to below 300 F. The charcoal beds remove radioactive iodine to limit control room operator dose during a postulated accident. During the extreme temperatures experienced in the summer of 1998, the Train A control room emergency pressurization unit failed three consecutive surveillance tests on July 6, August 3, and August 31,1998. After each test failure, some corrective actions were implernented and the control room emergency filtration / pressurization system was subsequently restored to service. The licensee submitted LER 50-445/98008-00 on September 18,1998, after it was determined that the Train A control room filtration / pressurization system was potentially inoperable for greater than the Technical Specification allowed outage time. Technical Specification 3.7.7.1 required that, with one control room emergency filtration / pressurization system train inoperable, the inoperable train be restored to an operable status within 7 days or be in at least hot standby within the next 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> and in cold shutdown within the following 30 hours3.472222e-4 days <br />0.00833 hours <br />4.960317e-5 weeks <br />1.1415e-5 months <br />. The inspectors concluded that the Train A control room filtration / pressurization system heaters could have tripped under extreme design basis conditions for more than 80 days beyond the 7-day allowed outage time, which constituted a violation of Technical Specification 3.7.7.1. The inspectors also concluded that the surveillance test failures occurred over a period of several months and corrective actions were protracted but ultimately effective. The issue was closed as a noncited violation consistent with Section Vll.B.1 of the NRC Enforcement Policy in NRC Inspection Report 50-445(446)/98-0 To improve the control room emergency pressurization / filtration system reliability, the licensee implemented a design change intended to decrease the potential for an unnecessary trip. Design Change 12503, Revision 0, was approved on January 4, 1999. The design change increased the trip setpoint of the automatic and manual reset heater trip from the original setpoints of 205/215*F to 238/288 F, respectively. The purpose of the heater trips is to prevent the charcoal bed temperature from exceeding a 300"F limit established by American National Standards Institute /American Society of Mechanical Engineers (ANSI /ASME) Code N509-1976. The 300 F limit is intended to prevent the charcoal bed from releasing previously captured radioactive iodine through a process called desorption. If charcoal bed temperature reached 300 F some time after a postulated design basis accident, a significant amount of iodine could be release The inspector discussed these concerns with the licensee who agreed with the concern and wrote SmartForm SMF-1999-001744-0 Af ter reviewing Calculation X-EB-304-5, Revision 1, the inspector was concerned about the remaining margin to 300 F. The inspector noted that the maximum calculated charcoal bed temperature of 298.9 F included flow distribution and measurement inaccuracies but did not consider the heat of adsorption of iodine in the charcoal beds and the heat added by radioactive decay as required by the ANSI /ASME N509 Cod As iodine is adsorbed by the charcoal, it releases heat which would only serve to raise the temperature of the charcoal bed. The failure to include appropriate design control measures in Design Change 12503, Revision 0, is considered a Severity Level IV violation (50-445 446/9914-04) of 10 CFR, Part 50, Appendix B, Section Ill, " Design Control. This Severity Level IV violation is being treated as a noncited violation, s

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-20-consistent with Appendix C of the NRC Enforcement Policy. This violation is in the licensee's corrective action program as SmartForm SMF-1999-001744-0 The inspector observed the postmodification testing and reviewed the test results which indicated that the emergency pressurization filtration system was working properly. The inspector noted that, as long as the automatic reset heater trip worked, charcoal bed temperature could not reach 300 F. The licensee's subsequent operability evaluation concluded that, since the pressurization unit and the filtration unit were in series and both contained charcoal beds sufficient to adsorb any expected levels of iodine, the system was still operable. The inspector consulted with experts in the NRC Office of Nuclear Reactor Regulation which agreed with the licensee's operability conclusio Conclusions The inspectors identified that the licensee implemented a design change to the control room emergency pressurization system that did not conform to the ANSI /ASME Code N509-1976 requirement that the heat generated from radioactive decay and adsorption of iodine be considered when developing these setpoints. The failure to include appropriate design control measures in Design Change 12503, Revision 0, was a Severity Level IV violation of 10 CFR, Part 50, Appendix B, Section Ill, * Design Control. This Severity Level IV violation is being treated as a noncited violation, consistent with Appendix C of the NRC Enforcement Policy. The licensees immediate operability evaluation concluded that the design change error did not affect the radiation dose to operators for a postulated design bases accident. The licensee appropriately placed the issue in their corrective action program (SmartForm SMF-1999-001744-00).

E8 Miscellaneous Engineering issues E8.1 (Closed) Temporary Instruction (TI) 2515/141. " Review of Year 2000 (Y2K)

Readiness of Computer Systems at Nuclear Power Plants" The inspectors conducted an abbreviated review of Y2K activities and documentation using Temporary Instruction (TI) 2515/141, " Review of Year 2000 (Y2K) Readiness of Computer Systems at Nuclear Power Plants." The review addressed aspects of Y2K l management planning, documentation, implementation planning, initial assessment, detailed assessment, remediation activities, Y2K testing and validation, notification activities, and contingency planning. The inspectors used NEl/NUSMG 97-07," Nuclear Utility Year 2000 Readiness," and NEl/NUSMG 98-07," Nuclear Utility Year 2000 Readiness Contingency Planning," as the primary references for this review. The results of this review were combined with the results of other reviews in a summary report which can be reviewed on the NRC internet home page located at:

httDMwww.ntc.aov/NRC/Y2K/olantstatus.html.

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s-21- 1 E8.2 (Closed) Inspection Followup Item (IFI) 50-445:-446/9903-01: ECCS throttle valve erosion effects on ability to perform hot leg recirculatio In 1996, the licensee identified the potential for throttle valves in the ECCS to erode under high flow and high differential pressure conditions. This condition was determined to have no adverse impact on the operability of the ECCS, with the exception of the system's ability to perform hot leg recirculation. The licensee considered the throttle valves to be degraded components in the system and addressed this condition using NRC Generic Letter 91-18," Resolution of Degraded and Nonconforming Conditions." A justification for continued operation (JCO) was prepared wnich referenced a Westinghouse safety evaluation that stated hot leg recirculation was unnecessary to maintain long-term cooling capabilities of the core post accident. This safety evaluation had been submitted to the NRC staff for review and consideration in licensing actions, but it was ultimately withdrawn in 1998 after preliminary reviews by the staff indicated that the assumptions made in the evaluation were not adequately supporte Regardless, the licensee did not revise their JCO until the inspectors questioned its validity in December 199 Furthermore, in December 1998, the licensee revised their pressure-locking and thermal binding evaluation for a number of motor-operated valves at the request of the staff reviewing the licensee's response to NRC Generic Letter 95-07, " Pressure Locking and Thermal Binding of Safety-Related Power-Operated Gate Valves." As a result, the licensee declared the residual heat removal pump discharge cross-tie valves in both units inoperable due to postaccident pressure locking concerns. This rendered the hot leg recirculation capability of the residual heat removal system inoperable, in response, the licensee performed an operability evaluation for the ECCS which concluded that hot leg recirculation remained operable through the safety injection system hot leg flow path. This was in direct contradiction to the existing JC The inspectors discussed the contradiction between the JCO and the ECCS operability evaluation with the licensee and a third operability evaluation was prepared which concluded that the safety injection system hot leg recirculation flow path was degraded but, overall, the ECCS would perform its safety function and all the requirements of 10 CFR 50.46 were me The inspectors consulted with the NRC Office of Nuclear Reactor Regulation and concluded that the emergency core cooling system remained operable despite the nonconforming condition associated with throttle valve erosion. The licensee took adequate and timely corrective actions to address this condition. Although no violation of regulatory requirements was identified, the licensee f ailed to consider the degraded throttle valve issue in an operability evaluation associated pressure locking of motor- !

operated valves. The licensee's failure to consider synergistic effects of multiple l degraded conditions was a departure from past good performanc !

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E8.3 (Closed) Violation (VIO) 50-445:-446/9803-04 and LER 50-445/97002-00; four examples of failure to verify or check the adequacy of design of the ECCS switchover procedur i s

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-22-The inspector reviewed the corrective actions implemented by the licensee for this violation, which included revision to emergency operating procedures and revision of affected calculation. The inspector concluded that the corrective actions were reasonable and verified that they were complete. No similar problems have been identified since the issuance of this violation. This violation is close E8.4 (Closed) VIO 50-445:-446/9803-05: failure to maintain records of safety evaluations which provided bases for the determination that the changes to the procedures for ECCS switchover did not constitute an unreviewed safety questio The inspector reviewed the immediate corrective actions for this violation, which included revision to the applicable safety evalur. tion and emergency operating procedures. In addition, the licensees review guide for performing 10 CFR 50.59 reviews was revised to addrer.$ the root cause of this violation. The inspector verified that corrective actions have been completed and concluded that they were appropriate to this violation. No similar problems have been identified since the issuance of this violation. This violation is close IV. Plant Support R1 Radiological Protection and Chemistry Controls R General Comments (71750)

The inspectors observed good radiological practices being implemented by plant personne Workers were familiar with their radiological work permit requirements. The inspectors accompanied licensee personnelinto the Unit 1 containment during power operations and observed good contamination controls and dose maintained as low as is reasonably achievable (ALARA).

F2 Status of Fire Protection Facilities and Equipment F TAy of Fire Protection Facilities a, l..aoection Scope (71750)

The inspectors walked down areas inside the plant and outside areas within the protected area for fire hazards. The operability of fire alarms, extinguishing equipment, fire barriers, firefighting, and other emergency equipment was examine Observations and Findinas The inspectors used Standard Operating Procedure SOP-904," Fire Protection Water Supply and Fire Pumps System," Revision 8, to verify that the fire main was properly aligned for standby operation. The fire pumps were in good conditio :

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-23-The inspectors noted that the plant was generally free from the storage of combustible material. Flammable material was observed to be properly marked and stored in designated storage containers. Fire suppression equipment inside the plant was in very good condition and ready for us c. Conclusions The inspectors verified that plant fire protection equipment and systems were in good condition and generally available for immediate use. Combustible material was minimized and properly stowed in the plan V. Manaaement Meetinos X1 Exit Meeting Summary The inspector presented the results of the inspection to members of licensee management on August 26,1999. The licensee acknowledged the findings presente No proprietary information was identifie l

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ATTACHMENT SUPPLEMENTAL INFORMATION PARTIAL LIST OF PERSONS CONTACTED Licensee C. L. Terry, Senior Vice President and Principal Nuclear Officer M. R. Blevina, Vice President, Nuclear Operations J. R. Curtis, Radiation Protection Manager R. Flores, System Engineering Manager D. L. Walling, Plant Modification Manager D. Kross, Outage Manager D. L. Davis, Nuclear Overview Manager INSPECTION PROCEDURES USED IP 37551 Onsite Engineering IP 61726 Surveillance Observations IP 62707 Maintenance Observations IP 71707 Plant Operations IP 71750 Plant Support Activities IP 92700 Onsite Followup of Written Reports of Nonroutine Events at Power Reactor Facilities

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IP 92902 Followup - Maintenance IP 92903 Followup - Engineering IP 93702 Prompt Onsite Response to Events at Operating Power Reactors l

ITEMS OPENED. CLOSED. AND DISCUSSED Opened 50-445/9914-01 NCV Inadequate storage of wnplant equipment (Section O2.1)

50-445;446/9914-02 NCV Missed Technical Specification surveillance on steam generator gross activity composite sample (Section M8.1)

50-446/9914-03 NCV inadequate work instructions resulted in nonconforming auxiliary feedwater check valves being installed in the plant (Section E1.2)

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-2-Closed 50-445/9914-01 NCV Inadequate storage of nonplant equipment (Section O2.1)

50-445;446/9914-02 NCV Missed Technical Specification surveillance on steam generator gross activity composite sample (Section M8.1)

50-445;446/99002: LER Missed Technical Specification surveillance on steam generator gross activity composite sample (Section M8.1)

50-445/99003 LER Unit 1 battery surveillance testing was not performed with the proper periodicity (Section M8.2)

50-446/9914 03 NCV inadequate work instructions resulted in nonconforming auxiliary feedwater check valves being installed in the plant (Section E1.2)

- Tl 2515/141 Tl Review of Year 2000 (Y2K) Readiness of Computer Systems at Nuclear Power Plants (Section E8.1)

50-445;446/9903-01 IFl ECCS throttle valve erosion effects on the ability to perform hot leg recirculation (Section E8.2)

50-445;446/9803-04 VIO Four examples of failure to verify or check adequacy of design of the ECCS switchover procedure (Section E8.3)

50-445/97002-00 LER Failure to verify or check adequacy of design of the ECCS switchover procedure (Section E8.3) ,

50-445;446/9803-05 VIO Failure to maintain records of safety evaluations which provided bases for the determination that changes to the procedure for ECCS switchover did not constitute an unreviewed safety question (Section E8.4)

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-3-LIST OF ACRONYMS USED ALARA as low as is reasonably achievable ANSI American Nuclear Standards Institute ARV atmospheric relief valve ASME American Society of Mechanical Engineers CCI Control Components, In DM design modification ECCS emergency core cooling system EHC electrohydraulic control IFl inspection followup item JCO Justification for Continued Operation LER licensee event report MWe megawatt electric NCV noncited violation NEl Nuclear Energy Institute NUSMG Nuclear Utility Software Management Group PIR plant incident report RHR residual heat removal rpm revolutions per minute Tl temporary instruction i

VIO violation t