IR 05000498/1992024

Insp Repts 50-498/92-24 & 50-499/92-24 on 920705-0801. Violations Noted.Major Areas Inspected:Plant Status & in-office Review of Written Repts of Nonroutine Events at Power Reactor Facilities

ML20127D503
Person / Time
Site:	South Texas
Issue date:	09/09/1992
From:	Howell A NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION IV)
To:
Shared Package
ML20127D481	List: IR 05000498/1992024 ML20127D478 ML20127D495
References
50-498-92-24, 50-499-92-24, NUDOCS 9209150073
Download: ML20127D503 (24)

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APPENDIX _B U.S. NUCLEAR REGULATORY COMMISSION

REGION IV

NRC Inspection Report: 50-498/92-24 Operating License: NPF-76 50-499/92-24 NPF-80 Dockets: 50-498 50-499 Licensee: Houston Lighting & Power Company P.O. Box 1700 Houston, Texas 77251 Facility Name: South Texas Project Electric Generating Station (STP),

Units 1 and 2 Inspection At: Matagorda County, Texas Inspection Conducted: July 5 through August 1, 1992 Inspectors: J. I. Tapia, Senior Resident Inspector R. J. Evans, Resident Inspector G. L. Gue, , Radiat Specialist Intern ( .

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A. T How ll, Chief, P70 ject Section D-f($

Dale Division of Reactor Projects Inspection-Summary inspection Conducted Jul_y 5 through August 1.1992 (Report 50-498/92-24:

50-499/92-24)

Areas Inspected: Routine, unannounced inspection of plant status, in-office review of written reports of nonroutine events at power reactor facilities, followup of unresolved items and an NRC Information Notice, followup on corrective actions for a violation, operational nfety verification,- monthl maintenance observations, bimonthly surveillance observations, and

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verification of plant records (Temporary Instruction 2515/115).

Results: In the area of plant operations, several- problems were identified-during this inspection period. A violation was cited for an inadequate electrical auxiliary building-heating, ventilation, and air )

conditioning (HVAC) system procedure (Section 3.2.3). Feedwater system equipment problems continue to challenge plant operators; however, operators responded-well to a resulting steam generator water level transient  !

(Section 4.5), and licensee management demonstrated conservative action to reduce unit power while steam generator feedwater pump problems were corrected (Section 4.8). A weakness was identified in the control of emergency dies:1 9209150073 92091o PDR ADOCK 05000490 G PDR

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-2-generator operability status (Section 6.2). . Licensee and.NRC reviews identified inconsistencies in the quality of operator area tours (Section 7).

In the area of maintenance, several long-standing equipment problems were again identified, including the emergency aiesel generators (Section 4.6) and

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Westinghouse Model DS-206 circuit breakers, which will be tracked by an inspection followup item (Section 5.1). Inadequate corrective actions associated with resolving essential chiller design and procedural weaknesses resulted in- a violation of 10 CFR part 50, Criterion XVI (Section 4.1). The inspectors noted that Steam Generator Power-0perated Relief Valve 2B failed,

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in part, because of a delay in correcting a previously identified deficiency (Section 5.2). - The licensee was slow to enhance essential chillar maintenance procedures following the identification of procedural weaknesses approximately 6 months ago (Section 3.2 1). The licensee was implementing, however, several

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- enhrncements to the work process program in order to improve the _

implementation of plant maintenance and design modifications (Section 4.9).

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In the area of surveillance, the licensee identified problems with the reliabi'.ity of certain solid state protection system test switches (Section 6.1) and an inadvertent engineered safety features (ESF) actuation occurred because of a technician error (Section 4.4).

Technical Support Center support system and equipment problems and a lack of preventive maintenance had the potential for reducing the level of protection to emergency workers (Section 3.2.2).

Several- temporary modifications which are greater than 2 years ald have not been removed or made into permanent modifications. Future inspections of temporary modifications will be tracked by an unresolved item (Section 4.3).

A list of acronyms and initialisms is provided as an attachment to this repor (

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-3-DETAILS

. PERSONS CONTACTED Houston Lighting & Power Com2any

• H. Bergendahl, Manager, Technical Services

• J. Blevins, Supervisor, Procedure Control

• Coughlin, Senior Licensing Engineer Dally-Piggott, Engineering Specialist, Licensing

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• *D. Denver, Manager, Nuclear Engineering

• D. Hall, Group Vice President

• R. Hernandez, Manager, Design Engineer

• Jump, Manager, Nuclear Licensing ,

• D. Leazar, Manager, Plant Engineering

• G._Parkey, Plant Manager

• R. Rehkugler, Director, Quality Assurance

• S. Rosen, Vice President, Nuclear Engineering

• J. Sharpe, Manager, Maintenance

• L. Weldon, Mar,ager, Operations Training In addition to the above, the inspectors also held discussions with other licensee and contractor personnel during this inspectio * Denotes those individuals attending the exit interview conducted on July 31, 199 . PLANT STATUS (71707) ,

Unit 1 began the inspection period at 100 percent power. The unit remained at full power until July 8,-1992, when power was reduced-to 95 percent to increase the-margin for a potential reactor trip v:ith one overtemperature differential temperature channel out of service. On July 12, 1992, unit power was increased to 100 percent following corrective maintenance and testing of the overtemperature differential temperature trip channel. Unit 1 remained at full power through the end of the inspection perio Unit 2 began the inspection period at 100 percent power. The unit remained at 100 percent powar until. July 9, 1992, when power was reduced to 80 percent to allow for repair of_Stean Generator.Feedwater-Pump 23, which had tripped earlier in the day._ The repairs were completed and unit power was increased to full power the next day. The unit remained at 100 percent power through the end of the inspection perio During the inspection period, .the licensee created the position of deputy plant manager. The responsibilities of the position included: (1) assist.ing the plant manager in the administration of routine station activities,

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(2) representing the plant manager on selected committees and task forces,.

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(3) performing special projects and studies as assigned by the plant manager, I

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-4-and (4) exercising full signature authority for the plant manager in his absence. The director of the Independent Safety Engineering Group (ISEG) was selected to fill the position of deputy plant manager, effective July 16, 199 . INSPECTOR FOLLOWUP in-Office Review of Written Reports of Nonroutine Events at Power Reactor Facilities (90712)

3. (Closed) Licensee Event Report (LER) 50-498/92-02: Containment Integrit_y TS Violation 3.2 Followup (9270 "

3. (Closed) Unresolved item (498;499/9134-02)

During an inspection ccnducted in January 1992, problems were identified with the essential chilled water system essential chiller flow switches. The flow switches had a history of Jrifting out of calibration. This problem generated 8 false chilled water low flow signals which had inhibited starting of the associated chiller. The cause of the calibration drift was suspected to be the result of a less than adequate switch design or the method of placing the switch into operation. The switches were differential pressure switches that have no equalizing valves. The licensee determined that improvements were needed in the method of switch calibration and in the instrument valving process to avoid.overranging the switches. The adequacy of the associated maintenance procedures was considered unresolved pending further inspection followu A station problem report was issued to investigate the problems encountered with the flow switches. The calibration and postmaintenance test methodology was reviewed, replacement of the switches with a different design or manufacture was considered, and a design change to install an equalizing line for each switch was initiated. The methodology for testing the switches at atmospheric pressure, instead of at line pressure, was considered to be in accordance with normal industry practices. A study of switch manufacture and design was performed and the licensee concluded that a change in switch design was not warranted. A design change request was submitted to add equalizing valves to the switches; however, this activity was not scheduled to be implemented (if approved) until 1994. Therefore, as a minimum, procedure cautions were determined by the inspectors to be required to minimize the chances of switch malfunction during the valving-in process. The licensee agreed that a caution in the procedure would provide appropriate, interim measures.to preclude problems while placing the switches into operatio During an inspection performed on July 17, 1992, 6 months after the original event, the inspectors determined that precautions had not been incorporated into the applicable maintenance procedures. Since switch calibrations wer:

performed using a generic procedure, the essential chiller preventive

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-5-maintenance instructions should have been revised to include the required precautions or other instructions on how to correctly valve-in a calibrated flow switch. The licensee requested the chiller vendor to provide additional informati 9 on how to correctly calibrate the flow switches. The vendor verbally recommended that a static pressure test, a process not normally used at STP, be used to calibrate the flow switches. At the end of the inspection period, the vendor had not supplied STP with revised calibration instruction During May 1992, the onsite plant engineering department determined that cautions on valving-in the switches and to valve-in the switches with the essential chilled water pump secured were needed to reduce the risk of switch damage. A maintenance feedback request was issued to incorporate this recommendation; however, the form was closed out with no action taken because of a misunderstanding on which department was going to take responsibility for completion J the assigned activitie The problem with the flow switches was identified in January 1992. Corrective actions were not taken to revise the maintenance procedures until prompted by the inspectors in July 1992. Failure to adequately address essential chiller procedural and design problems is a violation of 10 CFR Part 50, Criterion XVI (498;499/9224-01)

3.2.2 Followup of Information Notice 92-32 NRC Information Notice 92-32, " Problems Identified With Emergency Ventilation Systems for Near Site (Within 10 Miles) Emergency Operations Facilities and Technical Support Centers," was issued on April 29, 1992. ihe notice was released to alert licensees to potential problems resulting from inadequate maintenance and testing of Emergency Operations facilities and Technical  ;

Support Center (TSC) emergency ventilation systems. These-problems could result in a situation after an accident in which the Emergency Operations Facilities or TSC would not provide the level Of protection to emergency workers that was originally intende In response to the notice, an inspection of the Unit 1 TSC ventilation system was performed. A walkdown of the TSC HVAC system was performed using Procedures IP0P02-CH-0004, Revision 2, " Technical Support Center Chilled Water System," and IP0P02-HE-0002, Revision 1, " Technical Support Center HVAC System." All components were in the proper position to support system operation. Valve 1-CH-1401, TSC Chiller llB discharge throttle valve was required to be in the locked throttled position. However, the valve was found throttled but was not locked and was missing its identification tag. This valve was located on the electrical auxiliary building (EAB) roof. The inspectors noted that the material condition of equipment located outside was generally less than the equipment located inside. tne EAB. For example, Valve 1-CH-1394, TSC Chiller llB manual isolation valve, was observed to have a heavy accumulation of rust and corrosion on the manual operator. The licensee initiated corrective actions in response to this observatio _ - _ _ _ _ _ _ _ _ _ _ _ _ _ - _ _ - _ _ _ _ _ _ - _ - _ _ - _ _ _ - _ _ _ _ _ _ _ _ _ _ _ _ - _ _ _ _ - _ _ - - -

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-6-A review of the PM schedule for the chilled water .ystem was performe The chilled water pump.s, system motor-operated valves, and pump discharge pressure gauges were routinely inspected by the licensee. The remainder of the system components, including the TSC chillers, were not routinely inspected under the-PM program because the PMs were inactivated. On June 9, 1992, Unit 2 power was reduced about 5 percent for 1 1/2 hours because various computer alarms and indications of secondary side equipment temperature were steadily risin The cause of these indications was elevated tem,.erature in the plant computer room which affected the reliability of the plant computer. TSC Chiller 21B tripped off line and Chiller 21A failed to start. This allowed the room temperature to rise about 15af until the condition was discovered and r corrected. One of the causes of the event was the reliability of the room coolers and TSC chillers. PMs were not provided on the equipment because of the low priority levels established for these component "

During the chilled water system walkdown, two valve alignment discrepancies were identified. The TSC computer room air handling unit Discharge Throttle Valve 1-CH-1354 and TSC computer room air handling unit manual Inlet Isolation Valve 1-CH-1434 were found out of position. The procedure and drawing required Valve 1-CH-1434 to be locked throttled, but t'ne valve was full open with no lock. The procedure and drawing listed the required position of Valve 1-CH-1354 as full open, but the valve was throttled open with no loc The valve positions have since been corrected by operations. The inspector noted that on March 11, 1991, operations personnel performed a walkdown of the Unit 1 TSC chilled water system in accordance with Operating Procedure IPOP02-CH-0004. Valve 1-CH-1354 was-left locked in place and Valve 1-CH-1434 was left open. The positions were not in accordance with the procedure and the documented justification was because the lineup was " wrong." No corrective actions were taken to revise the apparently incorrect positions in the operating procedure. These valve alignment discrepancies had no effect on system operation. In addition, miscellaneous typographical errors, such as incorrect valve locations, were identified but were not corrected through the

_ procedure field change request proces During the inspection period, the Unit 1 TSC diesel generator was test started

- to verify operability. The_TSC diesel generator provides a source of power to the Load Center Bus 1W. The 480 volt load center supplies power to the TSC chillers and Motor Control Center (MCC) 1G8. This MCC provides power to the TSC chilled water pumps, selected air handling units, and other important, but nonsafety-related components. MCC 1G8 also provides power to the positive displacement pump (PDP). The primary purpose of the PDP is for hydrostatic-testing of the reactor coolant system. However, the PDP can be used to provide reactor coolant pump seal injection flow and reactor coolant boratiun capability for the abnormal condition when both centrifugal charging pumps are out of service (such as during loss of power events). Although nonsafety-related, loss of the TSC diesel generator durinc ertain accident conditions could hinder piant recovery action On July 23, 1992, a routine, quarterly start of the Unit 1 TSC diesel 6 generator was attempted. The TSC diesel generator start signal was generated

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-7-by opening the load Center _ Bus IW normal supply breake The TSC diesel generator failed to start. The licensee then attempted a local unloaded start of-the diesel generator but the machine failed to start a second tim Troubleshooting was performed and a defective solenoid was found on a diesel air start shuttle valve, which prevented the starting air support system from starting the engine. Spare parts were not available, but they were procured from an offsite vendor. Three days later, the TSC diesel generator was repaired and the machine was lccally started for an unloaded maintenance ru The following day, the TSC diesti generator was functionally tested with satisfactory result The TSC diesel generator reliability has been a concern at STP. The areas of concern include: the exposure to the environment (TSC dicsel generators are located outside), design inadequacies (such as technical manual and drawing errors) which have hindered operation and troubleshooting activities, and _

circuit breaker reliability. The 480 volt output breaker, manufactured by Brown Boveri, has a history of problems, including the failure to open or close upon demand. The Unit 1 TSC diesel generator only started 5 times of the last 8 start attempts while the Unit 2 TSC diesel generator only started 7 times of the last 10 start attempts. Trending of TSC diesel generators was being performed on a limited basis by the-cognizant system enginee The inspectors concluded that, collectively, TSC support system equipment problems and a lack of preventive maintenance had the potential for reducing the level of protection to emergency werker . (Closed) Unresolved Item 499/9214-02: Inoperable Make-Up Control Damper On June 3, 1992, a surveillance of Radiation Monitor 2RA-RT-8033 was performed in accordance with Procedure OPSP02-RA-8033, Revision 0, " Control Room / Aux Building Vent Monitor." This surveillance verifies that the radiation monitor will-alarm with a valid signal and that the control room envelope-(CRE)

ventilation system actuates and realigns to the required emergency configuration. _ Subsequent to the actuation of Train B of the CRE, a problem was noted during restoration of the system. Make-up Control Damper FCV-9585 indicated full open instead.of closed on the control room panel. However, the reactor operator noted Procedure OPSP02-RA-8033, Revision 0, " Restored Control Room Emergency. Ventilation and TSC-HVAC Systems Lineup," as satisfactory and terminated the_ surveillance. .At that time, the inspectors expressed concern-that the surveillance was exited even though Damper FCV-9585 did not perform as expected during system restoration. The failure to identify the ,

restoration of the system as unsatisfactory with Damper FCV-9585 not fully closed was identified as an unresolved ite During this inspection, the inspector reviewed the causes which contributed to the reactor operator indicating that ne restoration of the CRE was satisfactory even though Damper FCV-9585 had not fully closed. . It was determined that the restoration procedure, 2 POP 02-HE-0001, Revision 2,

"Elutrical Auxiliary Building HVAC-System," was deficient in that all

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-8-automatic system dampers were included in the restoration process except FCV-9585 and the corresponding dampers in Trains A and C. Therefore, the procedure did not provide sufficient guidance to ensure that the HVAC system would be returned to a normal lineup. The inspector identified the failure to perform an adequate restoration as a violation of TS 6.8.1.a (499/9224-02)

because the procedure utilized was inappropriate to the circumstance .3 Followup on Corrective Actions for Violations and Deviations (92702)

3. (Closed) Violation 498/9134-01: failure to Maintain Containment-Integrity On January 24, 1992, licensee personnel, prompted by inspector questioning, identified that on October 20, 1991, a violation of Technical Specification (TS) 3.6.1.1, " Containment Integrity," had existed for 47 hour5.439815e-4 days <br />0.0131 hours <br />7.771164e-5 weeks <br />1.78835e-5 months <br /> _

Repairs were made on.the secondary side of Steam Generator 10 with the unit in Mode 4, which resulted in a violation of TS for failure to maintain containment integrity. . The 1icensee issued Licensee Event Report-(LER) 50-498/92-002 identifying the violation and corrective actions to

be taken. Corrective actions taken included providing additional training on steam generator boundary and containment integrity requirements, revising

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maintenance procedures that are used to breach containment integrity, and issuing a bulletin to personn-1 who perform operability determinations to

. require them to use documents ther than TS, if necessary, to ensure license compliance. These actions were found to be acceptable and were completed within the committed time interva . OPERATIONAL. SAFETY VERIFICATION (71707)

The purpose of this inspection was to ensure that th' facility was being operated safely and in conformance with license and regulatory requirement The inspectors visited the control rooms on a routine basis and verified-control room staffing, operator decorum, shif t turnover, adherence to TS, and that overall personnel performance within the control room was in accordance with NRC requirements. Tours in various locations of the plant were also performed to observe work activities and to ensure that the facility was being operated in conformance with license and regulatory requeements. The following paragraphs provide details of specific inspector observations during this inspection perio .1 Essential Chiller Reliability and Unavailabilit_y (Unit 2)

The licensee has experienced problems with Essential Chiller 21A. On March 24, April 3,.and April 30, 1992, Chiller '21A was started to reclaim oil from the lower sump. All three times the chiller was started, the chiller tripped on low oil pressure. At operations' request, maintenance personnel manually pumped. oil up from the lower' sump using a hose and the auxiliary oil r pump. Following the completion of a 30-minute anti-recycle time delay, thb chiller was restarted each time and operated with no problems being -

identified. On May 10, 1992, the chiller again failed to start and a service

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_ request was issued to troubleshoot the cause of this failure. The compressor oil pressure switch was subsequently determined to be defective and was replaced. No problems have been observed with Chiller 21A since the switch was replaced. The four trips appear to have been caused by the defective

. pressure switch. ~The previous trips were worked under a generic service request for oil reclamation and the chiller trips were not flagged as a problem mtil the fourth tri The excessive number of trips indicated a weakness existed in essenti.1 chiller trending and the corrective action progra The inspectors were reviewing essential chiller reliability and unavailability rates at the end of the inspection period. This review will be tracked by Inspection Followup Item 498;499/9224-0 .2 Radiation Protection Control Observations (Units 1 and 21 ..

During this inspection period, the-inspectors made observations of the licensee's_ radiation protection program. Within the scope of this review, the 1adiation protection program was found to be effectively implemente .3 Temporar_y Hodifications (Units 1 and 2)

The-inspectors reviewed the status of outstanding temporary modifications and the procedural requirements contained in Procedure OPGF03-ZO-0003, Revision 11, " Temporary Modifications." This review disclosed that there were 42 outstanding temporary modifications in Units 1 and 28 in Unit 2. The oldest temporary modifications in Unit l'were approximately 4 years old. In Unit 2, the oldest temporary modifications were approximately 3 years ol The age of these temporary modifications indicated that they had become, in effect, permanent plant modifications, even .though the degree of configuration control for _ temporary modifications is less than that required for permanent plant modification The procedural requirements for' periodic reviews require, in part, that the Plant Manager and the Plant Engineering Manager review the status of all temporary modifications on a quarterly basis. ' This review is intended to minimize the total number of temporary modifications and to review the status of temporary modification restoration action plans.-The inspectors reviewed ,

the documentation for the last two quarterly periodic reviews. The meeting minutes disclosed that several recommendations for the generation of design change' notices were generated for the closure of several temporary modifications. However, these recommendations were not aggressively pursued as evidenced by'several relatively old temporary modifications. The inspectors did not perform a review of each outstanding temporary modification older than 2 years to assess whether the modification should have been incorporated into.the permanent plant documents in a more timely fashio This future review will be tracked by an unresolved item (498;499/9224-04) to determine whether licensee actions have been sufficient to adt <hese temporary modification _

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-10- V,n_ planned ESF Actuation (Unit 1).

On July 10, 1992, and unplanned ESF actuation occurred in Unit 1 during the performance of a spent fuel pool exhaust monitor (RT-8036) surveillance tes Instrumentation and Control (I&C) technicians were performing the test as required by TS. An erroneous value was entered into Control Module RM-23 The value of 1.52E-3 was entered when the value that should have been entered was 1.52+ Control Module RM-23A then processed the erroneous data and prematurely actuated the fuel handling building (FHB) isolation equipmen Control room operators acknowledged the ESF actuation as an unplanned event ~

and halted the surveillance test. The FHB equipment was then reset to the conditions required for the resumption of the surveillance tes The ,

surveillance test was then continued and completed without further inciden The inadvertent actuation resulted from a lack of attention to detail and from -

not using effective self-verification methods. An LER was submitted in accordance with 10 CFR Part 50.73(a)(2)(iv). Corrective actions taken by the licensee included providing the technician involved with a written reminder and performing an evaluation to determine which procedures need to be revised to ensure a dual verification is performed for those actions in which incorrect data entry errors could cause ESF actuations. This evaluation is scheduled to be completed by October 1, 1992. The inspectors will review this event further during a future inspection of the LER associated with this even .5 Feedwater Transient (Unit 2)

On July 7,1992, a small feedwater transient occurred in Unit 2 when Steam Generator 21 Feed Pump Recirculation Valve FV-7104 failed open. This caused steam generator levels to decrease because of reduced feed flow. Control room ,

operators responded expeditiously, stabilized feedwater flow, reduced turbine load, and returned steam generator levels to program values within a very short time. The lowest steam generator level experienced during the transient was about 47 percen Subsequent investigation revealed a fuse failure associated with a driver card for the recirculation valve. The card was subsequently replaced in accordance with approved work instructions. The control room operators responded well to this transient. The inspectors noted, however, that feedwater transients continue to challenge plant operator .6 EDG Problems (Units 1 and 2)

The licensee continues to experience problems with EDG The following problems were noted during this inspection period:

4. EDG 13 On July 5,1992, EDG 13 was declared inoperable because of a loss of both starting air compressors. Starting Air Compressor 16 had been taken out of

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service because of an air leak on the dryer skid when Starting Air Compressor 10 developed a gasket leak on th second stage outlet flange to the intercooler. The leak allowed ud.3 ,ur Receiver 15 pressure to drop below the required setpoint, 175 pounds per square inch (psi). The EDG m declared inoperable and TS 3.8.1.1.b was entered. Repairs to Ftarting Air Compressor 15 were initiated and, about 7 hours8.101852e-5 days <br />0.00194 hours <br />1.157407e-5 weeks <br />2.6635e-6 months <br /> later, EDG 13 wa; returned to service and declared operable. This condition could have been prevented had Starting Air Compressor 16 been repaired in a more timely manner. The original work request had not received a high priority and, therefore, the air compressor was not repaired in a timely fashio .6.2 EDG 23 On July 5,1492, EDG 23 was declared inoperable upon discovery of a failed motor for the standby fuel _ oil booster pump. The rump was started during "

troubleshooting by electricians. The pump amperage peaked at 78 amperes, resulting in the 15 ampere pump supply breaker tripping. As a result, the EDG was declared inoperable and the 72-hour TS action statement was entered. The lican.Me's engir.eering department subsequently determined that the EDG would operat4 satisfactorily without the operation of the standby fuel oil booster pump. The EDG has a-primary engine-driven fuel oil booster pump and a redundant, motor-driven fuel oil booster pump. In addition, there is a bypass

'line around both booster pumps which allows fuel oil from the fuel oil storage tank to reach the fuel injection pumps by gravity. As a result of the elevation-of the fuel tank, the _ engine fuel oil header pressure would be approximately 15 psi. The low pressure fuel oil alarm is set at 10 psi. The licensee obtained information from the vendor, Cooper-Bessemer, that indicated

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that they have operated this design of engine successfully at 15 psi. Based on this information, EDG 23 was returned to service prior to exceeding the TS action statement time. However, the licensee was-nct able to repair or replace the pump because there were no spares available. As a result, despite the engine remaining operable, the~ reliability of the engine was degraded since the preferred fuel oil boost pressure of 35 psi could not be achieve .6.3 EDG 22-On July' 8,1992, EDG 22.was started following scheduled maintenance and was '

placed in the cooldown mode after a successful start and run. When placed in the cooldown mode, the EDG tripped after 1 minute. Local alarms received when A the EDG tripped were " connecting rod high bearing temp" and " gen and bearing high temp alarm." Tripping-during the cooldown mode is a recurring problem .;

that previously has been investigated by the licensee. The cause of the '

engine tripping when placed in the cooldown cycle has been attributed to a I air leak in the nonemergency trip air header. The leak is not accessible i unless a complete e Hne overhaul is initiated. Although the leak does not l affect the ability er .he engine to perform its emergency design function, the l problem precludes the engine from going through a normal cooldown cycle. This results, over time, in reduced availability because of the troubleshootinF that is conducted to determine the causes of the proble I l

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-12-4. EDG 13 On July 8, 1992, during the performance of a routine operability test, EDG 13 tripped on low turbo lube oil pressure as indicated.by the local control board

. annunciator. Local lube oil pressure was subsequently verified to be adequate at 41.5 pound per square inch gage. The turbo lube oil pressure switch was replaced and calibrated. EDG 13 was then started, but it tripped again with the same indication. The interfacing valve between the lube oil system and the pneumatic trip header, PV-5699, was found not to be operating properly, &s evidenced by a continuous air discharge. When the cover for the valve was removed to provide access to the mounting bolts for removal, water was observed running out of the valve. The presence of this water led to corrosion within the valve cover, which prevented proper operation of the valve. The source of water was not clearly identified but was suspected to have entered the valve from pneumatic inlet header (valve is low point of the ,

pncumatic system) or from periodic cleaning of the EDG,

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4.7 Power Reduction Because of Instrumentation problems (Unit.1)

On July 8, 1992, a routine surveillance test of selected portions of the

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reactor coolant system (RCS) temperature logic was performed in Unit 1 in accordance with Procedure OpSPO-RC-0430, Revision 0, " Delta T and T Average Loop 3, Set 3, Analog Channel Operational Test." Less than 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> after the completion of the test, the Unit I control room received the Loop 3 overtemperature differential temperature reactor pretrip and turbine runback bistable alarms. The licensee dectried to reduce power from 100 to 95 percent to increase the margin for a reactor tri Service Request BS-185990 was issued to troubleshoot the cause of the alarms. The cause of the original problem was not clearly identified but was suspected to be the result of a E technician-bumping the gain settings of potentiometer located on logic card Two cards were replaced in the circuitry, and-a full calibration check of the circuitry was performed. The loop 3 Delta T and T average loop was returned to service following successful postmaintenance testing on July 12, 199 Unit Power Reduction Because of Eauipment Problems (Unit 2)

During the inspection period, the licensee continued to experience problems with balance of plant equipment. Steam Generator Feedwater Pump (SGFP) 23 tripped off line as a result of a main oil pump (MOP) failur Unit 2 power was _ subsequently reduced when a startup SGFP trouble alarm was received. The licensee' has previously experienced problems with MOP trips wnich have resulted in unit power reductions and have unnecessarily challenged the plant oporators. On March 30, 1992, Unit 2 power was reduced from 100 to 60 percent following an SGFP 22 trip which resulted from an M0P failure. The-licensee has developed long-term corrective actions to resolve the problems associated with M0P trip On July 9,1992, Unit 2 was operating at full power when SGFP 23 unexpecte'J1y tripped off-line. Startup SGFP 24 automatically started as designed and Feedwater Booster Pump 23 was manually started to maintain steam generator

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i I-13-level. _About 2 minutes later, the control room received a startup SGFP 24 auxiliary-lube oil trouble alar After receipt of this alarm, the lube oil

- reservoir level, temperature, and pressure were verified to be adequate; nevertheless, the licensee commenced a reactor power decrease to 80 percent in order to increase the margin to a reactor tri SGFP 23 tripped off-line following a failure of- M0P 1. M0P 2 and the emergency oil pump started; however, SGFP 23 still tripped on low lube oil pressure. Following the failure of M0P 1,'a rapid decay in lube oil header pressure was experienced. The pressure dropped to the SGFP trip setpoint prior to the restoration of header pressure by MOP 2 and the emergency oil pump. A review of industry experience revealed that the most probable cause for the SGFP trips during M0P transfers was air binding in the pump casin The vendor, Westinghouse, recommended drill hg holes in the pump casing to allow ~for an adequate air vent path. The vent path has been installed in all -

three SGFPs in Unit 2 and on SGFP 13 in Unit 1. The vent path appears to prevent -air binding but now allows for a more. rapid pressure deca Af ter. review, a decision was made, with Westinghouse concurrence, to install a small hydraulic accumulator, used to feed the trip header through an orifice, to prevent rapid depressurization of the header. This design change was made to a power station outside the United States and has proven successful. The licensee plans to install the accumulators-in Unit 1 during the refueling

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-outage scheduled to begin in September 199 Similar changes will be made in Unit 2 at a later dat Service Request LP-164752 was issued to investigate and repair M0P 1. A blown control power Dise was found and-replaced, but the cause of- the fuse failure was not rlearly. identified. Thermography performed after fuse replacement did not reveal any electrical' hot' spots. Servica Request FW-167140 was issued to investigate the startup' SGFP trouble alarm. A faulty level indication switch was found~and replaced. The repairs were completed and U' nit 2 returned to ,

ful: power operation on July 10, 1992',

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4;9 Implementation' of Work Process Program Improvements (Units 1 and 2)-

Late in'the inspection period, the licensee implemented major changes to the work process progra The program was implemented in an attempt to improve station performance and to streamline-the administrative workload associated with' scheduling and design change A work process task force was developed to evaluate each step of the maintenanco work control program. The task force was led by the maintenance manager. As part of.the overall program review, improvements were developed in_ the work scheduling, equipment clearances, and plant ~ design change processes. This coordinated effort was designated the Work Process Improvement Program. Wew and revised procedures were developed to enable [he station to plan and coordinate work activities more efficiently and reso'lve work related problems and design changes more effectively. The work proc improvement program was implemented on July 24, 1992, after procedure

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-14-development and employee trainin The following are highlights of the Work Process improvement Program:

A 7-week work schedule was developed to ensui1 that a routine ,

maintenance activity will be worked within 7 weeks of identificatio Craft personnel will know in advance what work will be performed and will be able to review the package in advanc * A group of technical sWoort engineers was established within the .

maintenance department. The engineers will work closeiy with the job planners and will be authorized to disposition nonconformances and

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issue certain design changes (usually based on cost) using a plant change form. Final design change approval, after implementation in most can s, will be required by the design engineering departmen This process will also reduce the number of modifications presented to ~

the modification review boar Service request forms can be used to identify the need for information or request a plant change, a process which will replace the request for action. form A relaxation in minor maintenance rules will allow maintenance personnel to perform more minor maintenance to reduce the administrative work load. .Also, the administrative activities of maintenance work supervisors was reduced to ensure increased-supervisor oversight of activities in progress in the plan a A "use as is" tag was added to the program. This tag-will be used to identify equipment problems, such as valve packing leaks, that will be reviewed and may be declared acceptable for "use as is" by engineering. -These tags will not be controlled or tracked through the use.of a master index but will be hung'on-the component in the plan F The equipment clearance order process was revised. Verification of properly implemented clearances will be performed by operations personnel, The authorized work supervisor will be allowed to lift the tag during the work activity. However, the-su)ervisor must sign off and onto each clearance at the beginning and tie end of each shif Conclusions

The licensee. continues to experience problems with essential chiller

. reliability and unavailabilit An excessive number of trips indicated that a weakness exists in the chiller trending and corrective action parram. This issue will be tracked by an inspection followup item. The licensee ~.,

radiation protection' controls were being effectively implemented. The review of outstanding temporary modHications disclosed that some long-standing temporary modifications have not been incorporated into the permanent plant documents in a timely fashion. This issua will also be tracked by an unresolved item. An inadvertent ESF actuation occurred as a result of poor . ..

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attention to detail by a technician during the performance of a surveillanc Operators responded well to a feedwater transient. The inspector noted that steam generator feedwater system problems continue to challenge the operator A Unit 1 power reduction was initiated as a result of problems with the Loop 3 overtemperature differential temperature circuitr Continuing problems with the EDGs resulted in increased EDG unavailability, in an attempt to improve station performance, the licensee initiated major changes in the maintenance work proces . MONTHLY MAINTENANCE OBSERVATIONS (6?703)

Selected maintenance activities were observed to ascertain whether the maintenance of safety-related systems and corponents was conducted in accordance with approved procedures, TS, and appropriate codes and standard The inspector verified that the activities were conducted in accordance with .

approved work instructicns and procedures, that the test equipment was within the current calibration cycles, and that housekeeping was being conh eted in an acceptable manner. All observations made were referred to the licensee for appropriate actio .1 Failure of Pump to Start Because of Breaker problems (Unit 2)

During the inspection period, the licensee continued to experience problems with the Westinghouse Model DS-206 480 Volt alternating current (AC) power supply breakers. On July 13, 1992, control room operators attempted to start Residual Heat Removal (RHR) Pump 28 from the control room. The pump start was attempted during the performance of the RHR Pump 2B reference values

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. measurement surveillance test; however, the pump would not start on deman The power supply breaker was racked out and back in at load center E2B, Cubicle 2B, to verify that it had been previously: racked in properly. A second attempt was made to start the pump but the pump again failed to star RHR Pump 2B was declared inoperable and Service Request RH-167137 was issued to troubleshoot the proble The licensee at first suspecad the breaker had a bad cell switch, but no problems were_ found with the switch. During the troubleshooting process, the breaker was cycled several times. Every other time the operators tried to close the breaker remotely from the control room, the breaker would not clos However, the breaker would manually close when pump control was transferred to the local panel. Although the problem was not clearly identified,-the

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licensee suspected the problem involved the spring release assembly or motor-cutoff switc To ensure the TS action statements were not exceeded, a decision was made to remove a spare breaker from an adjacent cubicle and place the breaker in the RHR Pump.2B breaker cubicle. The amptector (solid state trip device which provides a trip signal when predesignated current levels were reached) was removed from the defective breaker and installed on the spare breaker. Maintenance Procedure OPMP05-NA-0008, Revision 8,

" Westinghouse 4B0 Volt Breaker Test," was performed on the spare breaker, which was then inserted into the RHR Pump 2B cubicle. The postmaintenance test was satisfactorily completed and RHR Pump 2B was returned to service

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I-16-2 days later. The inspectors identified no problems during the changeout of the breake The licensee returned the defective breaker to the warehouse and planned to subsequently send it to the vendor for fault analysis and repai The vendor analysis was not completed by the end of the inspection perio The licensee has experienced other problems with the DS-206 breakers in the past. On May 25, 1992, RHR Pump 1A failed to start the first two times when the handswitch was taken to start. The pump started after the third attemp The failure description was not positively identified but was thought to be the result of high resistance in the close circuit because of a slightly loose connection at the secondary contacts. Other examples included: (1) EAB Supply Fan llB failed to trip on January 10 and 14, 1992, following maintenance and on August 8, 1991; (2) Reactor Containment fan Cooler (RCFC) .

12B f ailed to start on Aurnst 4, 1991; (3) the RCFC 228 breaker failed to open on October 22, 1990; (4) EAB Supply Fan llB would not open locally, in November 1990; and (5) RCFC llc would not trip on February 22, 199 The problems with the 0S-206 breakers have also occurred at other nuclear pl ants . Additionally, NRC has issued several generic documents in response to problems with Westinghouse breakers. NRC Information Notice 92-44, " Problems With Westinghouse DS-206 and DSL-206 Type Circuit Breakers," was issued to alert licensees about a condition that could cause the subject breakers to fail to open when required. The notice discussed problems with improper adjuscment or misalignment of the stationary and moving contacto Additionally NRC Bulletin 88-01, "00fects in Westinghouse Circuit Breakers,"

discussed problems with pole shafts. In response to the industry wide problems, Westinghouse issued several technical bulletins, including NSD-TB-91-06-R0, "DS-206 and DSL-206 Breakers - Mechanical Friction of Main Contact Assemblies." The licensee received the bulletin in November 1991 and has since incorporated the information into their maintenance program. As a result of the industry experience, the licensee planned to inspect 10 percent of their DS-206 breakers using the Westinghouse Bulletin. Licensee actions associated with DS-206 circuit breakers will be tracked by Inspection Followup Item 498;499/9224-05, 5.2 Inoperable Steam Generator Power Operated Relief Valve (PORV) (Unit 2)

During the inspection period, Unit 2 PORV 2B failed to open on demand. The cause of the problem was identified as internal hydraulic fluid leakage which resulted in a trip of the hydraulic pump and loss of hydraulic fluid pressur Corrective actions were nct complete at the end of the inspection period, in part, because of a lack of spare parts. This problem was identified in late 1991. The failure of the licensee to resolve the problem when initially identified ultimately led to the failure of the PORV in July 199 Each unit at STP has four main steam lines. Each main steam line has a P0d The PORVs are required for removal of heat from the primary side during periods when the condenser is not available as a heat sink or when the main

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steam isolation valves are closed. The PORVs are equipped with electrohydraulic actuators and are controlled through the qualified display processing system. The valves will open automatically, based on eteamline pressur Remote manual operation was provided at the control room main control board and the auxiliary shutdown panel. Mechanisms for local control, using a hand- pump, are proviaed in the event of complete loss of remote automatic or manual control. A nitrogen charged accumulator is provided on ,

each PORV. If power is not available tu the hydraulic pump, there is sufficiently stored energy in the PORV accumulator for about one and one-half valve stroke On July 17,-1992, Unit 2 operators attempted to stroke PORV 2B. The stroke test was to be performed using the routine surveillance procedure in response to the discovery of a high particulate count in the hydraulic n uid. 'he surveillance test results were unsatisfactory because the PORv' did not open .,

upon deman The PORV was declared inoperable and the TS 3.7.1.6 7-day shutdown action statement was entered. Preliminary investigations revealed that the hydraulic pump thermal overloads were open (pump not operating),

accurulator nitrogen low pressure alarm was not in an alarm condition (indicating adequate nitrogen pressure existed), and a hydraulic fluid pressure switch was found to be stuc The PORV hydraulic pump normally cycles on low and high hydraulic fluid pressure to maintain the hydraulic fluid pressure within a predetermined range (1500 to 1950 psig) required for valve operability. The normal pump cycle time is-approximately 2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br />; however, the licensee had previously experienced problems dating back to late 1991, with the pump short cycling (cycling on -and off too frequently). Prior tn the PORV failure, the cycle time was once per 16 minutes, The vendor manual provides instructions that maintenance is required if -the cycle time-drops to 10 minutes or less. The licensee suspected the short cycle time caused the premature failure of the high pressure switch. This conditio1 caused the pump to run continuously since the pump was designed to stop when the pressure switch opened. With the

- switch stuck closed, the pump continued to run until the thermal overloads opened, which deenergized the pump. The cause of the high particulate count rate was. suspected.to be pump wear products, a phenomena that was previously identified in the hydraulic fluid of PCRV 2C in May 199 To verify operability,-the PORVs are normally stroked on a monthly basis. The previous PORV 2B strok test was conducted on July 3, 1992. Since the lov nitrogen pressure alarm was not energized, the licensee could not determine when the PORV hydraulic pump tripped off line. When the hydraulic pump malfunctioned, hydraulic pressure decayed to atmospheric pressure in

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approximately 20 minutes. The accumulator piston then drove in as the result of decreasing hydraulic pressure; however, the low pressure alarm setpoint was not reached because of the pressure of the initial nitrogen charge and

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tightness of the nitrogen volume. Therefore, operations personnel were not aware of the low hydraulic fluid preL ire. The only alarm provided for the PORV hydraulic fluid is low reservoir level, which was never attaine .

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On July 19, 1992, the p0RV hydraulic fluid was cleaned and the pressure switch was changed out in accordance with Service Request 165 M2. The hydraulic pump was de-energized, and operations personwl then stroked the PORV on nitrogen presse The valve stroked full open and closed to 28 percent before the .

nitrogen low pressure alarm energized. The operators then terminated the test  ;

prior to total discharge of the nitrogen. The hydraulic pump was reenergized, the nitrogen pressure alarm cleared, and the hydraulic pump cycled off when adequate pressure was attained. Following successful postmaintenance testing '

and engineering evaluation, the PORV was declared operable the next da The inspectors noted, however, that on July 23, 1992, the PORV 20 w n again removed from service for troubleshooting in accordance with Service Request 1 163896. The licensee attempted to identify the cause of the degrad# pump performance, which was suspected to be the result of internal hydraulic leakage from the high pressure side to the lower pressure reservoir. The pump .

cycle time was noted to have dropped to approximately 7 1/2 minutes following )

the initial PORV rework. The source of leakage was not clearly identified, ,

E but the licensee was able to narrow the scope of suspect components to three

items, Spare parts were not immediately available to complete the rework l

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process and the valve was restored to service the next day. Despite the pump

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cycle time being less than the-vendor recommendation of 10 minutes (minimum),

the licensee concluded (Request for Action 91-2092) that the valve operator will perform its safety function as long as the hydraulic pump developed the required pressure. The licensee was aware that the short cycle time of the

' ump could cause additional wear problems in the futur Jne corrective action completed on PORV 2B was to raise the nitrogen low pressure alarm setnoint from 1350 to 1400 psig. The alarm setpoints on the other PORVs will + *evised during future scheduled work outages. Spare parts for the completion of the PORV rework were scheduled to be received in August 1992. At that time, the PORV will again be removed from service for

- additional rework in an attempt to resolve this maintenance i_ssu .

Conclusions The licensee continued to have problems with the Westinghouse 05-206 breakers but has developed a long-term plan of action to investigate these breaker problems. These actions will be tracked by an inspection followup ite .

PORV 28 failed to operate during the-inspection period. The PORV failed, in part, because of the delay in the repair of a known deficiency. A lack of spare parts resulted in a further delay of the rework of the valve. The inspector noted that this could result in the potential for further valve degradat_ ion because of increased wea ,

6, BIMONTHLY SURVE!L.LANCLOBSERVATIONS (617261 i Selected activities were observed to ascertain whether the surveillance ofs l plant systems and components were being conducted in accordance with TS and other requirements. The inspection included a review of the procedures Deing used, assurance that the test equipment was correct for the task being ,

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-19-performe6. and verifying that dhta measured was within acc atance criteria limits. All comments and observations were reported to the licensee for resolution, t 6.1 Loalc Train functional Test (Unit 21

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The Train S automatic trip and automatic logic output functions of the solid state protection system (SSPS) in Unit 2 were tested on July 20, 199 Problems with selected test switches were encountered during the test. The ,

test was completed with no logic failures; however, the test equipment was determined to need repair or rework in the near futur The reactor trip system consists of the analog system (process and nuclear instrumentation subsystems), reactor trip switchgear, manual trip circuitry, and the SSPS. The SSPS consists of two redundant logic trains (R and 5) and ..

three actuation trains (A, B, and C). The SSPS takes an input from the analog system in binary form (voltage present or no voltage ) resent) corresponding to ;

normal or abnormal conditions. The system combines tTeso signals in the required logic combination and generates a trip signal when the necessary combination of input signals exis TS Table 4.3-1 requires that each logic train be tested at least once every 62 days, on a staggered test basis. Therefore, each month the R or S Train is tested. On April 16, 1992 SSPS Logic Train S was tested in accordanco with Surveillance Procedure OPSP03-SP-0005S, Revision 2, SSPS Logic Train S Functional Test." During the performance of the surveillance, problems were identified with the Logic C function selector switc The switch in Position 24 was suspected to be intermittently malfunctioning because of dirty contacts. The test was completed with satisfactory results because no logic failures were identified. Proceduro OPSP03-SP-0005S was performed again on June 20, 1992. No problems were identified during the subsequent surveillance test performanc On July 20, 1992, the surveillance test was performed again. During the performance of the test, additional problems were identified with the automatic input function test. -The problems were encountered with several functional-selector switches, not just the Logic C switch. The test performer had to depress the test pushbutton multiple times for selected logic checks until the logic test for each section was completed. The test took longer than expected but the test was competed with no logic test failure If the test switches or pushbutton had failed, the licensee would have stopped-the test and restored the equipment to operable. TS 3.3.1 allows one channel (R or S) to be bypassed'for up to 2 hour2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br />s- for surveillance testing, provided the other channel is operable. An alternate test method was available in a procedure that incorporated-the use of jumpers to open selected switch contacts. This procedure, written exclusively for failure of the Logic C switch, would allow the SSPS logic train to be tested; however, the surveillance would take more than 2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br /> to complete. Therefore, if the :.est-switches had failed, the licensee would have had to request a Temporary Walver

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P-20-of Compliance from NRC to allow for relief from the 2-hour time limit imposed by TS Table 3.3-1. Also, the alternate procedure would have to have been revised since the problem was not limited to the Logic C switc i Surveillance OPSP03-SP-0005S was scheduled for its next implementation on ,

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September 14, 1992. The licensee planned to monitor equipment performance closely to determin's whether the test could be completed or if a requast for Temporary Waiver of Compliance would be necessary. Short-term corrective ,

actions planned included reviewing the logic to determine what the potential .

problem source was and determine whether the problem could be fixed with the unit at power. Longer term actions planned included test equipment replacement during a future unit shutdow .2 Verification of Correct Breaker Alignment (Unit 11

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On July 3, 1992, following ,Janned maintenance and testing of the Train B ECW system, the system was returned to operable status at 1:40 p.m. At 9 p.m. the same day, EDG 12 was declared operable. The next morning at 8:27 a.m., the licensee declared ECW Train B screen wash booster pump discharge check Valve EW-254 inoperable because the postmaintenance test was incomplete. The required flow rate check had not been performed to verify flow actually would >

pass through the valve. Because ECW Train B was still inoperable, EDG 12 was considered inoperable during the same perio With an EDG_ inoperable, TS 3.8.1.1.a requires the' licensee to ensure that two physically independent circuits between the offsite transmission nntwork and the onsite Class IE distribution system were operable. Operability is demonstrated by performing the TS 4.8.1.1.a Surveillance Requirement within 1-hour and at-least once each 8 hours9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br /> thereafter. The operability check consists of verification of correct breaker alignments and indicated power availabilit Procedure IPSP03-EA-0002, Revision 5, "ESF Power Availability,"

was the surveillance procedure that is used to document the performance of TS Surveillance Requirement 4.8.1, ;

'Durir.g the period between 9 p.m. on July 3, 1992, and 8:27 a.m. the next morning,-when EDG 12 was inoperable, one TS 4.8.1.1.a 8-hour surveillance check was missed. The last time the ESF power availability surveillance was completed was at 6:2S p.m. on July 3, 1992. The surveillance was due at 2:25 a.m. the next morning but was not performed because EDG 12 had bee .

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returned to operable status. The surveillance was satisfactorily completed at 8:40 a.m. on July:4,1992. The missed postmaintenance test was completed at-9:23 a.m. on-July 4,1992, and .the ECW Train B and EDG 12 were declared operable. -The NRC operations center was notified of the missed surveillance at 12:30 p.m. on July 4. 199 Subsequent to the event, the licensee determined that the missed surveillance was not a reportable avent. Further. investigation determined that tredit

.could be taken for control- room operator board walkdowns ano alarm response to fulfill the TS surveillance requirements. The board walkdowns ensured that the verification of correct breaker alignment was accomplished. Theso

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-21-walkdcwr W 1 performed continuously and no changes in breaker alignments or alarmer' d4. ions were observed during the period that EDG 12 was coraidered operabi A actually was not. Therefore, the requirement to verify correct breaker uignment was f ulfilled but was not documented in the applicable procedure. The ?icensee concluded that the event was not reportable and informed the NRC Operations Center on July 17, 1992. Although no TS violation occurred because of coincidental compliance, the inspectors considered this to be a weakness in the control of safaty-related equipment by plant operator I In response to the event, the ESF power availability surveillance procedures were reviewed by the inspectors and compared to actual plant conditions. The

)ower supply breakers of both units were in the correct posi' ions established

)y the procedure lineups. The procedures were compared to M Updated Safety Analysis Report and TS. All Updated Safety Analysis Report and TS requirements for verifica; ion of offsite and onsite power sources were .

incorporated-into the procedures. the inspectors did note one missing link in the power supply distribution lineup. The safety-related output breakers between the Class lE 480 VAC load centers and 480 VAC MCCs were nnt listed in .

the procedures. Because of the wording in TS and the Updated Safety Analysis Report, these breakers were not considered part of either the onsite or offsite power sup)1y systems. However, the breakers had ta be closed to supply power to tie safety-related battery chargers, which were part of the onsite power supply syste Conclusion Problems were encountered with test switches during *he performance of an SSPS surveillance test. Equipment repair was determinec ' be needed to resolve the issue. One weakness was identified in the control of equipment-status by .

plant operator . VERIFICA110N OF PLAdT RECORDS (TLMPORARY INSTRUCTION 2515L1151 On April 23, 1992, NRC issued Information Notice 92-30, " Falsification of Plant Records," to alert licensees to the NRC's concern that plant mechanics,

' technicians, and operators may have falsified plant logs at several nuclear power plants. An NRC inspection was performed ht STP to determine whether the practices of individuals performing log entries were such that there is a potential for-record falsification to occu The inspection consisted of a walkdown of selacted logsheets to verify whether the required entries can be  ;

collected and recorded, determining whether or not the licensee has implemented a self monitoring program,-and comparing selected required room entries against security access record Procedure OPSP03-ZQ-0028. Revision 3, " Operator Logs," was used to record parameter values-necessary to track system and component performance and to

- satisfy numerous TS surveillance requirements. The procedure included a number of attachments, including the control room, mechanical and electrics 1 auxiliary building (MEAB),' turbine generator building, and yard logsheet On July 1,1992, 'a walkdown of the HEAB Logsheet OPSP03-ZQ-0028-14 was performed

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-22-in each unit during the second (day) shif The walkdown was performed with the nonlicensed operator assigned to the MEAB that shift. The walkdown was performed to ensure that the required logsheet data entries could be taken with the instrumentation installed in the plant and to ensure that the logsheets were technically accorate and complete. Several minor items were observed during the walkdown. For example, two radiological control signs were found on the floor of the Unit 2 MEAB. This condition was reported to the on-duty HP personne During the walkdown, the inspector noted that several rooms were not visited, including the auxiliary shutdown panel, two nonsafety-related electrical distribution panel rooms, and most electrical cable raceway and conduit rooms, procedure OPOP01-ZQ-0022, Revision 1, " Plant Operations Shift Routines,"

Section 5.3, provides instructions to operators on how tn perform area and equipment checks during local operator rounds. Section 5.3 states, in part, -

that watchstanders should inspect all areas and equipment within the respective watchstation. However, the inspectors noted that the room numbers were not explicitly identified in the procedur The inspectors considered this to be a weakness. Overall, the operator logsheets for the MEAB were '

comprehensive and could be pe.' formed as written. All walkdown observations were reported to the licensee for corrective action as neede The inspectors also performed a review to determine whether the licensee had developed and implemented a comprehensive self-monitoring program. In response to NRC Information Notice 92-30, the licensee performed a sample review of operator logs versus access records as part of a quality assuranc audit of physical security. The review concentrated on operatar rounds of the isolation valve cubicles, diesel generator bays, and the essential cooling water structure for the period covering I week in April 1992. No situations were identified which indicated that any potential falsification issues existed. Several discre)ancies were identified, including the early performance of rounds, tie use of trainees, and the length of time in selected areas. These issues werc still under review by the licensee at the end of the inspection perio No formal program currently exists for self-monitoring of log taking activities, in the past, potential- falsification issues were handled through the independent verification process, occasional supervisory checks, and specific investigations. Training sessions and seminars were also conducted to communicate management's standards and expectations for employee performance. The licensee-plans to perform an interdepartmental review of this subject area by October 1992. Any corrective actions which might result will be developed on the basis of the results of this revie The inspectors selected a number of MEAB watchstanders and verified, using security access records, that the required FHB entries were made during their respective shifts. 'Of the entries reviewed, the MEAB watchstanders did enter the FHB during their designated shifts. During the day and evening shifts; the 'only two items recorded were two tell-tale drain leakage rates (used to determine whether the spent fuel pool or transfer canal's liners were

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I-23-t leaking). All other data were recorded on the 12 midnight to 8 a.m. shif This data included recording of tbc spent fuel pool parameters, located in a contaminated are The inspectors noted that one midnight shift tour of the FHB for a Unit 1 MEAB ,

operator lasted only 11 minutes. The major'+y of the entries made during this shift were 20-30 minutes in length. The inspectors independently determined that the required data entries could be completed by one person in 11 minute However, the required data entries and a complete building walkdown could not '

have been reasonably completed in a quality manner in such a short period, particularly since a partial dressout for contamination control was required for two data reading Conclusions

No instances of watchstander log entry f alsification were identifie However, the apparent failure of the operations watchstanders to perform inspections of consistent quality is considered a weakness in the implementation of such activitie . EXIT INTERVIEW The inspectors met with licensee representatives (denoted in paragraph 1) on July 31, 1992. The inspectors summarized the scope and findings of the inspection. The licensee did not identify as proprietary any of the information provided to, or reviewed by, the inspector ,

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ATTACHMENT LIST 0E ACRONYMS AND INITIAllSMS

'CRE contioi room envelope EAB- Electrical Auxiliary Building ECW- essential cooling water EDG emergency diesel generator ESF engineered safety features fHB fuel Handling Building HP health physics HVAC heating, ventilation and air conditioning '

ISEG Independent Safety Engineering Group LER iicensee event report MCC motor control-center MEAB Mechanical Electrical Auxiliary Building M0P mainooil pump NRC U.S. Nuclear Regulatory Commission ..

PDP positive displacement pump PM preventive maintenance PORV power operated relief valve RCA radiation controlled area RCFC reactor containment fan cooler RHR residual heat removal SGFP steam generator feedwater pump SSPS- solid state protection system STP South-Texas Project Electric Generating Station TS Technical Specifications TSC Technical Support Center

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