IR 05000219/1993021

Insp Rept 50-219/93-21 on 930810-0920.No Violations Noted. Major Areas Inspected:Operations,Maint,Engineering,Plant Support & Safety Assessment/Quality Verification

ML20058Q165
Person / Time
Site:	Oyster Creek
Issue date:	10/15/1993
From:	Rogge J NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION I)
To:
Shared Package
ML20058Q124	List: IR 05000219/1993021 ML20058Q120
References
50-219-93-21, NUDOCS 9310260095
Download: ML20058Q165 (23)

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A N' U. S. NUCLEAR REGULATORY COMMISSION

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REGION I'

Report N Docket N ' License N DPR-16 i-  : Licensee: - GPU Nuclear Corporation p 1 Upper Pond Road

~ Parsippany, New Jersey 07054 u

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Facility' Name: . Oyster Creek Nuclear Generating Station Inspection Period: August 10,1993 - September 20,1993

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l Inspectors: Steve Pindale, Resident Inspector l Joe Schoppy, Resident Inspector (Salem / Hope Creek)

Larry Briggs, Senior Operations Examiner Dave Vito, Senior Resident Inspector Approved By: 4 -

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yJohn Rogge, Sectio $hisf Date Reactor Projects Section 4B Insnection Summary: This inspection report documents the safety inspections conducted c during day shift and backshift hours of station activities including: operations; maintenance; enginecting; plant support; and safety assessment / quality verification. The Executive

' Summary delineates the inspection findings and conclusions -

l Results: Overall, GPUN operated the facility in a safe manne l l

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W' ' TABLE OF CONTENTS Eiige

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EXEC UTIVE S U MMARY ; . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . _ . . . . . . . . ii

[1'.0 ' OPERATIONS (71707,93702) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . I Operations Summary . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1 Facility Tours ......._.............................. 1

- Reactor Cleanup Demineralizer System Reduced Flow . . . . . . . . . . . . . 1 MAINTENANCE (62703,61726) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2 Maintenance Activities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . ' 2 Light Socket and Relay Replacement for 4kV Vital Bus . . . . . . . . . . . 3 Surveillance Activities ................................ 3 Temporary Interruption of Surveillance Procedure Performance . . . . . . . 5 ;

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2.5- Surveillance Test Results Discrepancy . . . . . . . . . . . . . . . . . . . . . . . 5 3.0' ENGINEERING (71707,40500)' . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6 Temporary suction Strainer Installed on Plant Equipment (UNR 50-219/93-21-01) ..................................... 6 Temporary Modification for Reactor Recirculation System Automatic Trip Circuit (UNR 50-219/93-21-02) ....................... 7 Emergency Diesel Generator No.1 Failure To Start . . . . . . . . . . . . . . 8 V Bus Second Level Undervoltage Relay Setting Inadequacies (UNR 50-219/93-21-03) ............................... 9

- PLANT SUPPORT (71707,92701) . . . . . . . . . . . . . . . . . . . . . . . . . . . . 12

. Radiological Controls . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 12 ,

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4.1.1 Inattention to Postings . . . . . . . . . . . . . . . . . . . . . . . . . . . 12 S ecu ri ty . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 13 4.3' Emergency Preparedness . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 13 4.3.1 Onsite Preparedness for Hurricane Emily . . . . . . . . . . . . . . . 13 o Fire Protection . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 14 4.4.1 Fire Watch Implemented Following to Vital Switchgear Fan

- Failure .................................... 14 SAFETY ASSESSMENT / QUALITY VERIFICATION (2500/28,40500,71707) . 14 Employee Concern Program (Temporary Instruction 2500/28) .... .. . 14 Performance-Based Quality Assurance Implementation Effort ....... 15

, Review of Previously Opened Items . . . . . . . . . . . . . . . . . . . . . . . 17

. EXIT MEETINGS (40500,71707) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 19 i Preliminary Inspection Findings ............. ........... 19 ' Attendance at Management Meetings ...................... 20 o

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EXECUTIVE SUMMARY

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Oyster Creek Nuclear Generating Station Report No. 93-21

- Operations GPUN operated the unit safely. Operators temporarily reduced reactor water cleanup system flowrate to less than :;pecified by the operating procedure on two occasions, however, a temporary procedure change was not implemented until prior to the second occasion. A more in-depth review prior to initial implementation should have been performed since the-licensee ultimately determined that to be the conservative and appropriate approac Maintenance Inspection in this area found generally good performance. During the performance of one a

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_ surveillance test, operators secured from the test and then continued the test during the following shift without implementing the appropriate controls to ensure proper system restoration (when stopped) and to ensure that all necessary prerequisites were reverified

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(when restarted). This practice represented a potential for temporarily leaving safety systems

- in an undetected inoperable conditio Engineering :

The licensee adequately prioritized and executed engineering work activities. However, several engineering items were unresolved during this inspection, requiring prompt licensee attention. The inspectors opened an varesolved item after identifying a strainer in the reactor building closed cooling water system that was not consistent with system drawings. It was not apparent that the licensee had haplemented timely or appropriate actions when informed of the potential for the failure to remove the temporary strainer from the construction phase of operations. The licensee implemented _a temporary modification, which defeated a specific automatic reactor recirculation pump trip without thoroughly evaluating the change, and is an unresolved item. A third unresolved item was identified because additional licensee effort is needed to resolve issues regarding available voltages to equipment supplied by the 480V vital f buses due to existing second level undervoltage relay settings for the 4kV buse Troubleshooting and evaluation was accomplished successfully after the emergency diesel generator No.1 failed to star ,

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Plant Support Periodic inspector observation of station worker and radiological controls personnel noted

. generally good implementation ~of radiological controls program requirements. GPUN conservatively and effectively prepared for a forecasted hurricane. The onsite fire watch personnel properly implemented the required hourly fire watch for an inoperable 4kV vital switchgear room fire barrie .

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Safety Assessment /Ouality Verification i

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The licensee maintains an established formal program, providing employees the ability to . raise nuclear safety concerns outside of their established management chain. The licensee

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was making positive progress in the implementation of QA performance-based assessment and the development of a workable' set of performance indicators for the line organizatio l

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p- ::4 DETAILS OPERATIONS (71707,93702)

. . Operations Summary The plant operated at or near 100% power for the entire inspection period, with one exception. Plant operators reduced reactor power to about 38% on August _20 - 21,1993, in order to perform the quarterly main steam isolation valve full closure test. Full power

, operation was resumed at 11:00 p.m. on August 21,199 .2 Facility Tours The inspectors observed plant activities and conducted routine plant tours to assess equipment conditions, personnel safety hazards, procedural adherence and compliance with regulatory

- requirements. Tours were conducted of the following areas:

• control roo * intake area

• . cable spreading room * reactor building

• diesel generator building * turbine building

• new radwaste building * vital switchgear rooms

, e old radwaste building e access control points

-* transformer yard Control room activities were found to be well controlled and conducted in a professional manner. The inspectors verified operator knowledge of ongoing plant activities, equipment status, and existing fire watche .3 Reactor Cleanup Demineralizer System Reduced Flow On August 26,1993, the licensee reduced cleanup system flow to 262 gallons per minute

~(gpm) to reduce heat load to the reactor building closed cooling water (RBCCW) syste Operating procedure 303,." Reactor Cleanup Demineralizer System," requires flow be maintained at 380-400 gpm. However, the procedure establishes the minimum flow of 114

- gpm in step 2.2.4.1, for the purpose of holding the cleanup filter cake in place. The licensee restored cleanup flow to normal after approximately four hours of operation at reduced flo The licensee determined that the flow reduction had no adverse affect on the reactor plant and had reduced RBCCW temperatures by three degree The licensee subsequently evaluated the effects of reduced cleanup flow and pursued a temporary plant change (TPC). This change was not an " urgent change" as defm' ed in administrative procedure 107, " Procedure Control," and therefore required implementing approval as described in administrative procedure 103, " Station Document Control."

F On August 31,1993, the licensee implemented Revision 46 to procedure 303 to allow the system to be operated at low flow for the purpose of reducing the heat load on RBCC This constituted a one time temporary procedure change, in accordance with procedure 103, not to exceed 90 days. The licensee determined that the change did not affect nuclear safety or safe plant operations.

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The inspectors discussed the need for an_ engineering review to be- performed prior to operation at reduced flow with operations management. Management stated that the pumps were monitored for vibration during reduced flow operation, and that the procedure did not -

specifically disallow operation at reduced flow. The inspector noted that procedure 107

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_ called for an engineering review prior to implementation of a substantial TPC. This review had been established in response to a programmatic weakness identified in the TPC process during NRC Inspection 50-219/93-80 (Augmented Inspection Team (AIT) - Degraded Shutdown Cooling Event). The degraded shutdown cooling event involved a more substantial change than reactor water cleanup system operation at reduced flow; however, a

_ pre-implementation engineering review may have been appropriate as a conservative measur The inspectors reviewed the cleanup system operating procedures, component descriptions and functions, and_demineralizer effluent chemistry following the flow reduction. The chemistry trending was inconclusive due to the short time at reduced flow. However, the inspectors noted that chemistry personnel were aware of the flow reduction and were closely monitoring plant chemistry for possible. effects. The inspectors determined that the cleanup system operation at reduced flow on August 26,1993 was acceptable because 1) the cleanup pumps 'were monitored for vibration; 2) the 114 gpm minimum flow requirement of procedure 303 was not exceeded; 3) the time duration was short; and 4) chemistry personnel were monitoring reactor coolant system chemistry for adverse effects. However, the ,

inspector questioned whether the lack of a specific proceduml prohibition should imply-acceptance to. operate outside of a prescribed operating range. A more in-depth engineering

= review prior to iniplementation on August 26,1993, may have been appropriate since the licensee ultimately determined that to be the conservative approac .0 MAINTENANCE (62703,61726) Maintenance Activities The inspectors observed selected maintenance activities on safety-related equipment to ascertain that the licensee conducted these activities in accordance with approved procedures,

- Technical Specifications, and appropriate industrial codes and standard The inspector observed portions of the following activitie Job Order (JO) or

- Work Request (WR) N l'escription WR 762433 Replace light socket for IL8D on 4kV vital bus ID WR 762483 Remove louvers and mesh on reactor feed pump motor IA to remove insulation 30 49185 Isolation condenser valve MOVATS testing-JO 49186 - Retorque packing gland on isolation condenser valve V-14-34

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l The maintenance activities inspected were ' effective with respect to meeting the safety

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o bjectives of the maintenance progra I 2.2 - Light Socket and Relay Replacement for 4kV Vital Bus .

On August 31,1993, while electricians were replacing an undervoltage trip light for the "D"

" . 4kV vital bus, an electrical short occurred. The electrical department subsequently

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performed a portion of the undervoltage channel functional test and verified operability of the associated undervoltage relay. The' inspectors observed the related maintenance activities to replace the associated light socket and light circuit relay (No. 27-12XTD) on September 1 and September 2,1993, respectively. The inspectors observed that the electricians used extreme caution while working in the energized 4kV bus. While the environmental 6 - conditions included high temperature, limited space and slightly reduced lighting, the l electricians exercised good work practices, which included wearing the proper protective clothing and properly insulating lifted leads. The circuit was satisfactorily retested following the maintenance. The inspectors concluded that the activities observed were well planned and execute .3 Surveillance Activities The inspectors noted that properly approved surveillance procedures were in use, approval was obtained and prerequisites satisfied prior to beginning the test, test instrumentation was properly calibrated and used, radiological practices were adequate, technical specifications were satisfied, and personnel performing the tests were qualified and knowledgeable about the test procedur Procedure N Description i 604.3.001 Reactor Building to Torus Power Vacuum Breaker Test and Calibration 610.3.115 Core Spray System 1 Instrument Channel and Level Bistable Calibration and Test and System Operability )

612.4.001 Standby Liquid Control Pump and Valve Operability and In-service Test 619.3.001 Turbine Load Rejection Scram Test (> 45% load)

632.2.002 Grid Undervoltage Channel Functional Test-636.4.003 Diesel Generator load Test r

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- Overall, the surveillance testing activities inspected were effective with respect to meeting the safety objectives of the surveillance testing program. The verbal communication between the

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personnel performing the test activities and the control room operators were particularly l noteworthy. Personnel frequently used repeat-backs to ensure that requests / instructions were clearly understoo i Temporary Interruption of Surveillance Procedure Performance On August 30,1993, the licensee conducted surveillance procedure 619.3.001, " Turbine Load Rejection Scram Test (> 45% Load)." The licensee determined that the components tested were satisfactory with minor discrepancies noted. A deviation report was initiated for emergency trip oil pressure switch setpoint drift, which resulted in low "as found" pressure readings. The "as left" switch setpoints fully met the acceptance criteria. The licensee determined that relay chattering prevented several plant computer indication actuations. The licensee previously identified a similar relay chatter and had initiated job order #47822 to address'the proble The inspectors reviewed the surveillance procedure results and determined that the surveillance was satisfactorily performed. However, upon review of the operator's log, the inspectors noted that the licensee " secured" from the surveillance at 3:07 p.m. on August 30, and then recommenced the test at 6:30 p.m. on August 30. The 3:07 p.m. log entry stated that the system was returned to normal and that the surveillance would continue on the next shift. In reviewing the surveillance test, the inspector found no documentation of the temporary stoppage. There was no documentation to support an independent verification of affected valves upon system restoration prior to shift change. In addition, no documentation was present to demonstrate that the oncoming shift received group shift supervisor (GSS)

permission or reverified prerequisites prior to recommencing the surveillance. The l inspectors acknowledged that the same GSS was present on the next shift, the surveillance )

was recommenced early in the shift, a final independent verification of all required valves i was conducted, and the surveillance itself was satisfactorily completed. Although no I problem occurred, the inspector noted a potential for future problems. The licensee's (

I surveillance test program guidance does not specifically address partially completed surveillances. In particular, an incomplete surveillance does not require the same

- independent verification of system line up as does a fully completed surveillance, and no time limitation between securing and recommencing is stated. Improper system restoration could result in system inoperability, which could remain undetected for a significant length of tim In addition, failure to reverify test prerequisites could result in unnecessary plant transients or unsafe test conditions. The inspectors informed station management of these concerns, who stated that they would review this issue to determine whether programmatic guidance would be appropriat !

2.5- Surveillance Test Results Discrepancy Early in the inspection period, the inspector reviewed recently completed surveillance tests for the control rod drive (CRD) system. Surveillance procedure No. 617.4.001, "CRD Pump Operability Test," monitors several parameters during the monthly test, including CRD ;

charging water pressure and CRD pump discharge pressure. During the tests, as well as l

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r during normal operating conditions, the CRD pump discharge pressure has been F approximately 70 - 80 psig greater than the CRD charging water pressure for the "A" CRD i pump. 'However, the inspector identified that the April 21,1993, completed test documented

that the "A" CRD discharge pressure was 1450 psig and the "A" CRD charging water pressure was 1480 psig, a pressure / flow relationship which cannot physically occu Completed surveillance test procedures are reviewed by senior reactor operators and

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Operations staff personnel, as well as the responsible system engineer. The inspector's review concluded that the results for all other surveillance tests reviewed demonstrated the

. appropriate pump discharge / charging water pressure relationshi The inspectors brought this concern to the licensee's attention, who determined that it was an isolated incident. The inspector did not question system operability (all surveillance test acceptance criteria were satisfied) but expressed a concern to the licensee that several personnel had reviewed the data without identifying the deficiency. The inspector will continue to review surveillance test data to confirm that this is an isolated incident and that test results are reasonabl .0 ENGINEERING (71707,40500) Temporary Suction Strainer Installed on Plant Equipment (UNR 50-219/93-21-01)

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During a routine plant tour, the inspectors noted that there was a plate installed at a flanged connection on the suction side of one of the two reactor building closed cooling water

'(RBCCW) pumps. Each RBCCW pump has an elbow on the suction side. The plate was located at the vertical flange of the elbow for the No.1-2 pump. The No.1-1 pump did not contain a similar plate at the suction elbow flange. System drawings did not indicate the presence of any device (e.g. an orifice or strainer) at the flange. The inspectors questioned the licensee about the plate, who subsequently informed the inspectors that the device was a conical, in-line strainer that was apparently installed during plant constructio The inspectors determined that the NRC had issued Information Notice (IN) No. 85-96,

" Temporary Strainers Left Installed in Pump Suction Piping," dated December 23,198 The licensee's internal review and response for IN 85-96 concluded that station administrative and procedural controls ensured the removal or disposition of temporary strainers. No apparent physical walkdown or verification was performed or documente On September 20,1993, the inspector reviewed documentation that had been maintained by the RBCCW system engineer associated with the suction strainer. The documentation included a planned preventive maintenance (PM) activity to periodically (once every two years) inspect the RBCCW suction strainer. The activity (Task No. 206M) was planned for January 1,1992. There was also a document in the system ' engineer's file (Plant En'gineering Work Request No. 90-04) that indicated that the same PM activity was scheduled for both RBCCW pumps (although only one pump had a strainer) for January 1, 1990. However, there was no documentation to confirm the actual performance of the PM y activit .I

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The inspector expressed the following concerns to the licensee:

-- IN 85-96 was closed based only upon administrative controls (no physical system

. inspection). In addition, it was not evident that the licensee identified the existence of the strainer until 1990 (approximately four years after issuance of the IN).

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PM activity was ultimately developed for the RBCCW suction strainer, however, there was no evidence to show that the PM was ever performe The' inspector noted that the RBCCW system is not a safety related system. However, the system cools operating auxiliary equipment (including the reactor recirculation pump and

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motor coolers and drywell. cooling fans), and a loss of the RBCCW system would require a

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- plant shutdown. In addition, the RBCCW system is the heat sink for the shutdown cooling

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system to remove sensible and decay heat during a shutdown. The inspector will continue to evaluate the adequacy of the licensee's response and followup for IN 85-96. Pending resolution of the configuration control and preventive maintenance questions related to this issue, including a review of RBCCW pump performance data, this item is unresolve . (Unresolved Item 50-219/93-21-01) Temporary. Modification for Reactor Recirculation System Automatic Trip

- Circuit (UNR 50-219/93-21-02)

On September 10, 1993, the licensee implemented temporary modification (TM) No. 93-38, which defeated one of the several automatic reactor recirculation (RR) pump trips for the "B" RR pump. The specific trip that was defeated occurs when the discharge valve and discharge bypass valve both leave the fully open position. During a review of the associated documentation, the inspectors identified a concern that a 10 CFR 50.59 safety evaluation may have been required; howeve , a safety evaluation was not don The TM was initiated after s. September 9,1993, control room alarm was received indicating

- an electrical ground on the 'B" 125 volt battery system. Subsequent investigation located the source of the ground in the "B" RR pump discharge valve trip circui The TM process is prescribed by administrative procedure 108.8, " Temporary Modification Control." Attachment 108.8-3 is the safety / environmental determination of the TM process,

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that determines whether a safety evaluation is required. Question No. 2 in that attachment states, in part, "Does the installation /use of this TM conflict with the system / component

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. descrQtion or operating description in the FSAR7"- If answered affirmatively, a safety I

evaluation is required prior to implementing the TM. The licensee answered the question

- NO, with the comment, "FSAR/[ Technical Specification] do not describe to this level of function.' ~ The licensee's final determination concluded that a safety evaluation was not require The inspectors reviewed FSAR Section 7.6.1.2, " Recirculation Pump Trip System," which lists 13 functions that automatically trip the RR pumps. The discharge / bypass valve closure trip was not included in this list. The inspectors questioned the licensee as to whether the discharge / bypass valve trip was not in the FSAR as a result of an oversight. If so, the

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inspectors questioned the licensee whether a safety evaluation would then be appropriat The inspectors concluded that the licensee's initial response was narrowly focused in that they stated that a safety evaluation was not required simply because the trip function was not listed in the FSAR. The licensee stated that a review would be initiated to process an FSAR dhange request, if deemed necessar i t

. The inspector did not identify any immediate safety concerns associated with the ii . implementation of the TM. However, the intent of performing a detailed safety evaluation

.when the facility,.as described in the FSAR, is changed is to ensure that the change does not

> introduce an unreviewed safety question. The inspector noted that the safety determination that was completed did not address any potential consequences of experiencing a condition E which would have necessitated the trip that was defeated. At the end of the inspection,

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GPUN management personnel stated that they would re-evaluate the existing safety determination. Additional information was necessary to determine whether the trip in question should have been described in the FSAR and to assess whether a safety evaluation should have been performed. Pending resolution of this issue, this item is unresolve (Unresolved Item 50-219/93-21-02)

- 3.3 . Emergency Diesel Generator No.1 Failure To Start At 9:00 a.m. on August 23,1993, emergency diesel generator (EDG) No. I failed to start when given a normal start signal from the control room during the performance of surveillance procedure 636.4.003, ." Diesel Generator Imad Test," Revision 45, dated March 19, 1993. The inspectors assessed the licensee's actions to troubleshoot, repair and return

- EDG No. I to servic After the diesel start failure, the group shift supervisor (GSS) immediately declared EDG No. '1. inoperable and entered the 7-day limiting condition for operation (LCO) action statement of technical' specification 3.7.C.2. A load test was then performed on EDG No. 2 and avas successfully completed at 11:15 a.m. The licensee then performed troubleshooting on the EDG starting circuitry. The troubleshooting effort identified a failed relay coil and

control rectifier. These components were replaced. On the subsequent start attempt of EDG No.' I at 8:30 p.m. on August 23,1993, an EDG No.1-Disabled alarm was received due to

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..a sequence fault. On this second start attempt, test personnel observed that the diesel started normally, accelerated, and began to synchronize, but that the output breaker did not clos Further troubleshooting identified a high resistance in one secondary c' ontact stab in the GE4160V Magneblast breaker. The output breaker was then racked out and back in again !

followed by a successful start of EDG No.1. EDG No. I was declared operable at 12:12 )

a.m. on August 24,1994, after successful completion of a load tes :

l The inspectors assessed the licensee's response efforts and discussed the reason for the )

. equipment failures with the system engineer. Control room personnel took prompt and 1 appropriate action to declare EDG No.1 inoperable and perform load testing on EDG N Initial engineering assessment found that the failed components would not have affected the diesel fast (emergency) start circuitry. However, the plant was kept in the TS LCO action

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. statement while diesel repair and subsequent post-maintenance testing were being performe nWhile the causes of the failed control rectifier and relay coil were not conclusive, the system l

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engineer noted that the control rectifier may have failed after a previous, diesel generator motorization incident. On August 31,1992, while cleaning the tag from the EDG N output breaker and removing the local diesel control switch from the pull-to-lock position after a maintenance' activity, an equipment operator (EO) inadvertently moved the control switch past the closed position causing the output breaker to close. With breaker closure, the generator on the secured EDG was reverse powered. The system engineer felt that the current surge' caused by the August 1992 motorization incident may have failed the control rectifier at that time. The failure of the rectifier did not have an effect on the test starting sequence until.the relay coil failure. In combination, the two failed components caused a sequence fault, preventing diesel star The second diesel start attempt failed due to a significant voltage drop across one of the breaker secondary contact stabs. Breaker condition did not appear to be a problem since the

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breaker had been overhauled in October 1992. The contacts were clean and appeared to

'have a normal amount of contact grease. After racking the breaker out and back in again, the voltage drop did not recur and the diesel was successfully started. The system engineer noted that this phenomenon had occurred at Oyster Creek in the past during breaker racking operations. Although the licensee has been unable to determine a specific cause for this phenomenon, they no_ted that the breaker connection problem had always been discovered prior to placing the breaker back into service during post-maintenance testing. The system engineer has subsequently distributed a list of questions to other utilities to determine whether

'similar breaker stab misalignment problems have occurred elsewher The inspectors concluded that control room personnel responded appropriately to the EDG No. -1 start failure on August 23,1993. Troubleshooting was accomplished successfully and

. the diesel was returned to se vice promptly.

< V Bus Second Levd Undervoltage Relay Setting Inadequacies (UNR 50-219/93-21-03)

On August 18, 1993, a material non-conformance report (MNCR) was written to document the findings of an engineering calculation of available voltages at components supplied with 480V vital power. The calculation used the existing technical specification (2.3.P.2)

degraded voltage settings for 4160V emergency bus undervoltage of 3671V 1% with a 10.0 i 1.0 second time delay, a worst case LOCA loading condition, and an assumed 12V voltage drop in the equipment control circuitry. The calculation determined that voltages at various safety-related components could be below the manufacturers design limit voltages (85% of rated) and below the minimum motor starter pickup voltages. The inspectors assessed the licensee's efforts in response to this MNCR. Overall, the inspectors found the

. licensee had taken appropriate actions to assess equipment operability and was planning

- appropriate future action to assess the potential need to change the 4kV second level undervoltage relay trip settings. However, while the licensee eventually reported this issue to the NRC as a condition outside the plant design basis per 10 CFR 50.72(b)(1)(ii)(8) on

' September 9,1993, the inspectors concluded that the licensee may have been able to make an earlier conclusion of reportability. based on available information.

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Shortly after the MNCR was submitted, a deviation report was written so that the issue could ;

be initially assessed for operability, reportability, and required level of root cause

! assessment. The licensee's initial determination on August 20,1993, was that more ;

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information was needed to determine whether there were any equipment operability problems or whether operation with the existing 4kV second level undervoltage trip settings could place the plant in a condition outside its design basis. Specifically, the licensee's initial efforts were focused on determining whether the load profile used in the engineer's calculation was consistent with the existing load profile as well as whether the assumed voltage drop for the equipment circuit (12 volts) in the calculational model may have been too conservative. While these initial assessments were being performed, a conditional release i was issued for the MNCR based on the' operability of the voltage regulators between the l 34.5kV offsite power sources and the~ startup transformers. With the voltage regulators in service, the voltages at the 4160V buses will remain within a range of approximately 4150V to 4300V. The conditional release noted that degraded grid conditions in combination with a failure of the voltage regulators was a low probability occurrence. If the startup ;

transformers are lost, ac power would be supplied by the emergency diesel generators which ;

have their own voltage regulator. The MNCR and its conditional release justification were ;

issued to control room operating crews for required reading on August 20,199 l The engineering calculation in question determined the voltages on all plant buses and, in particular, vital motor control centers (MCC) 1A2 and 1B2, using the DAPPER computer i i

code. A load profile calculation performed in 1991 was used to provide required bus loading information. The two primary changes in the load profile since the 1991 time frame were that 1) only one of the two condensate booster pumps are automatically loaded onto the vital buses in a LOCA scenario and 2) containment spray and emergency service water (CS/ESW)

is no longer automatically activated. However, CS/ESW could be started manually in an accident condition based on plant conditions as directed by the emergency operating procedures. While the load profile differences had a small effect on the voltage drop condition, the assessment of actual voltage drops in the equipment control circuits had a much more significant effect. The DAPPER model assumed a 12 volt drop to the motor starter relays. The licensee was not able to determine the basis for this value. It was not apparent whether this va'ue assumed full inrush current, holding current, or a combination of the two to calculate voltage drops across the MCC contacts. The licensee eventually determined that they would use the fullinrush current in their subsequent testing effort to determine actual voltage drops. The licensee's subsequent assessment and testing effort led them to standby gas treatment system fan EF-1-9 as the probable worst case situation. The power feed from 480V vital MCC IB24 to EF-1-9 appeared to represent the combination of cable size, cable length, and motor starter size that would develop the largest equipment circuit voltage drop (1400 ft of #12AWG control cable, with a NEMA size #2 starter and three control relays).

On September 8,1993, the licensee measured the actual voltage at the EF-1-9 fan motor starter and then performed a voltage drop calculation for a degraded voltage condition using the inrush current at the nominal rating for the motor starter coils and control relays. At the same time, pickup voltage bench testing was performed on several MCC motor starters of different ages,' sizes, and conditions to determine if motor starter condition could alter the actual results measured for EF-1-9. The resident inspectors discussed the results of this 6, . , _ _ _

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testing with the licensee on the morning of September 9,1993. The licensee note <1 at that time that, based on inrush current, it appeared that the voltage drop in the EF-1-9 control circuit could have been as much as 25-30 volts vice the assumed 12 volts. This indicated -

that the voltage at the motor starter may be below the design basis value (85% or 391 volts for EF-1-9). The licensee than noted that the bench tests of the MCC starter motors and the results of reviews of past preventive maintenance tests of motor contactor pickup voltages '

showed that the contacts repetitively picked up at voltages lower than the 85% design value, i.e., in the 70% range. The inspectors reviewed the licensee's data and concluded that

- although the voltages may drop below the 85% design rating, the motors would probably start in a degraded voltage condition where voltage at the 4kV buses remained above the second level undervoltage relay settings. However, the inspectors questioned the licensee as to why reportability of the condition had yet to be addressed when it appeared that the voltage at EF-1-9 could be below the design value. The licensee responded that they were still debating whether they were required to assume inrush current for the voltage drop calculation and that they would meet that afternoon to discuss reportability potential. The issue was reported as a condition outside the plant design basis per 10 CFR 50.72(b)(1)(ii)(b)

at 5:14 p.m. on September 9,199 The licensee's subsequent efforts included:

• Rechecking the circuits for all of the safety-related MCCs to assure that the worst case had been identified;

• Design verification of the calculations performed to support the equipment operability assessment;

• Formal documentation of the operability evaluation;

• Determine if adjusting the existing setting of the 4kV second level undervoltage relays to the upper limit of the setting tolerance band would significantly improve the current operating' condition; and

• Develop a longer term action plan to eventually determine whether a change to the existing 4KV second level undervoltage relay settings in the technical specifications is necessar A draft of the licensee's operability evaluation was provided to the inspectors by the end of the inspection period. The licensee's preliminary conclusions were that 1) the EF-1-9 circuit represented the worst case voltage drop condition, 2) voltage at the motor starters could be below the 85% design value, and 3) testing demonstrated that there was reasonable margin between actual starter pickup voltage and available voltage to the motor starters. The licensee evaluated the possibility of raising the 4kV second level undervoltage relay settings to their maximum value (from 3666V to 3671V) but concluded that the increase in available voltage at the 480V MCCs was insignifican a- .r

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s m _ The licensee tentative action plan for analyzing the undervoltage setpoints is as follows: 1. Complete voltage drop calculations down to the 120Vac level; 2. Review 230kV and 34.5kV grid voltage profiles for the last 5 years to determine minimum and maximum values. Specifically, this effort could help determine whether raising the 4kV second level undervoltage setting too high could be a problem; 3. Obtain and document all nameplate data for the safety related load circuits, i.e., motors, distribution transformer sizes and tap settings, fuses, starters, coils, etc; and 4. Perform an undervoltage setpoint analysis based on Items 1,2 and 3 to determine < whether setpoint changes may be necessary. Submit a proposed technical specification change if necessar The licensee' estimated that it would take approximately one year to complete items 1 through 4 above. The inspectors concluded that the licensee's actions to date have demonstrated that required safety-rela'ed t ' equipment would operate in worst-case conditions at the existing 4kV second level undervoltage relay settings. However, additional licensee effort is necessary to '. effect changes that will preclude the operation of equipment at voltages below design basis ' values. This issue is unresolved pending further review of the licensee's actions to resolve

- the current operating condition outside the design basis. (Unresolved Item 50-219/93-21-03)

4.0 -- PLANT SUPPORT (71707,92701)

' _ Radiological Controls During entry to and exit from the radiologically controlled area (RCA), the inspectors verified that proper warning signs were posted, personnel entering were wearing proper dosimetry, personnel and materials leaving were properly monitored for radioactive contamination, and monitoring instruments were functional and in calibration. During
. periodic plant tours, the inspectors verified that posted extended Radiation Work Permits
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(RWPs) and survey status boards were current and accurate. The inspectors observed activities _in the RCA and verified that personnel were complying with the requirements of applicable RWPs and that workers were aware of the radiological conditions in the are .1.1. Inattention to Postings     1 On September 1,1993, the licensee performed surveillance procedure 612.4.001, " Standby Liquid Control Pump and Valve Operability and In-Service Test." During the conduct of that surveillance, the equipment operator failed to properly notify Radiological Controls (rad con) prior to proceeding above seven feet as he proceeded to the top of the standby liquid control tank to verify that relief valve V-19-42 was still seated. The ladder leading to the top
'of the tank has a rad con posting indicating, " contact rad con prior to any access above seven feet." The inspector discussed the rad con posting with the operator. The operator stated that he should have called rad con. Prior to climbing the ladder again the operator contacted
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- rad con and was informed that the last radiological survey indicated no additional radiological precautions were necessary. The operator stated that the posting was relatively new and it was once routine to take tank level readings from that elevated platform. The use of a sonic level detector has rendered this practice obsolete and it is no longer routine to climb that particular ladder, hence the rad con postin . The inspector reviewed the August 2,' 1993, radiological survey of the liquid poison platform '

and determined that the contamination / radiation levels were quite low. The inspector' discussed these postings with rad con personnel and was informed that when contacted

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g concerning such a posting, the normal practice is to dispatch a rad con technician to survey ' the area prior to access. In this circumstance, an existing survey, within 30 days, was used to" permit access without further surveys. The inspector determined that based upon past radiological surveys of the area, this conclusion was appropriate. The inspector determined that better communication between rad con and operations could have prevented this occurrence. Rad con was present at the shift briefing covering planned maintenance and smveillance and could have mentioned the recent survey or reemphasized the need to contact F them prior to proceeding above seven feet. The inspector determined that the licensee took appropriate corrective actions for this occasion of operator inattention to detail and addressed the issue quickly when identifie f Security During routine tours, the inspectors verified that access controls were in accordance with the Security Plan, security posts were properly manned, protected area gates were locked or

- guarded, and isolation zones were free of obstructions. The inspectors examined vital area
- access points and verified that they were properly locked or guarded and that access control was in accordance with the Security Pla ' Emergency Preparedness 4.3.1'^ Onsite Preparedness for Hurricane Emily Late in ' August 1993, the National Weather Service was following the path of Hurricane Emily. There was a possibility that the hurricane could impact the Oyster Creek statio GPUN implemented several actions to prepare the site and station personnel for the stor Station personnel reviewed plant abnormal procedure 2000-ABN-3200.31, "High Winds," on August 30,1993, to determine what actions may become necessary. The licensee toured the
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facility to ensure that all compressed gas bottles and other equipment on wheels were secured. In addition, several sandbags were placed in specific plant areas to prevent water ; flooding conditions for vulnerable equipment. Other licensee actions included securing ; scaffolding that was installed adjacent to the standby gas treatment system fans, and moving l other outside equipment such as trash cans and picnic table l During a review of the abnormal procedure, the inspector noted that different operator l actions a' re required based upon predetermined high intake water levels. Those actions !

' included a controlled plant shutdown, and reactor scram, and emergency action level

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13 declarations. However, the inspector determined that operators can obtain intake level information locally only (i.e. there is no indication of intake level in the control room). The

' inspector questioned the licensee whether intake level. could physically be obtained due to )

personnel safety restraints during severe weather conditions such as extreme high wind The licensee stated that a remote means of observing the intake area was available so that appropriate operator actions can be take In NRC Inspection No. 93-11, the inspectors reviewed the licensee's read.iness for and

' prescribed actions in response to a hurricane, and concluded the licensee had established adequate precautions for the Oyster Creek site. During this inspection, the inspector toured the facility and attended several planning meetings, and concluded that the licensee conservatively and effectively prepared for the hurricane. However, the inspector ider:t:fied one concern related to the two water processing truck trailers located adjacent to the' station blackout transformer. The trailers did not appear to be physically anchored. The licensee
'also recognized this as a concern.- For this occasion, the hurricane did not impact the sit However, the licensee stated that the water treatment trailers would either be anchored, moved or evaluated to address this concer . Fire Protection 4.4.1' Fire Watch Implemented Following to Vital Switchgear Fan Failure On September 9,1993, a control room alarm annunciated related to a loss of the "C" and
 "D" vital 4kV switchgear room ventilation system. Plant operators responded to the area and
' found that the "C" ventilation fan had tripped due to thermal overload; the "D" fan continued to operate satisfactorily. Operators opened the associated roll-up door for_ the "C" switchgear room to allow for sufficient cooling of the "C" vital 4kV switchgear. The roll-up door is a fire barrier as documented in Administrative Procedure No.101.2, " Fire Protection
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Program." Therefore, as required by procedure 101.2, the licensee established a hourly fire watc The inspector reviewed the licensee's response to the fan trip and found it to be acceptabl In addition, the inspector obtained and reviewed a security system card reader printout for a selected period of September 10-12, 1993, to verify that the vital switchgear area was entered to conduct the required fire watch. The inspector confirmed the implementation of the hourly fire watch through the printout review, and verified completion of the associated fire watch log sheet. - The fan was subsequently replaced, and the fire watch for the area was -

, secured on September 21,199 .0 SAFETY ASSESSMENT / QUALITY. VERIFICATION (2500/28,40500,71707) Employee Concern Program (Temporary Instruction 2500/28)

' The inspectors evaluated the licensee's program providing employees the ability to raise

- safety concerns outside of their established management chain. At Oyster Creek, this

- program is referred to as the Nuclear Ombudsman Progra , - p 4  ;

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Originally, the Nuclear Safety Assessment Director, locMed at GPUN Headquarters in Parsippany, New Jersey was designated as the ombudsn.an. Since 1989, the office of the i' ombudsman has been expanded to include Manager, Nuclear Safety at each GPUN site (Oyster Creek and Three Mile Island). Employees are invited to bring their concerns to the

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ombudsman if not satisfied with results obtained through normal management channels or if they have a specific reason to not want to use those channels. Employees are made aware of - this program through general employee training (GET) and distribution of an outage administration guide prior to refueling outages. The primary purpose of the program is to evaluate concerns regarding nuclear safety. The program is not designed to apply to personnel or personal safety issues if they are not related to nuclear safety. The ombudsman will refer these 'other issues to proper channels. Personal safety issues are referred to the

: Safety Department. Union grievance-type issues are referred to the bargaining unit grievance process. Non-union personnel issues are referred to a different program called the Dispute Resolution Proces The ombudsman program applies to alllicensee employees. The current version of the program controlling procedure does not specify contractors but, in practice, contract
- personnel have not been excluded from use of the ombudsman program. The license indicated that a forthcoming revision of the controlling procedure would include contractor participhtion. .The licensee does not specifically require its contractors to have a similar program within the contractor's organization.

( Implementation of the ombudsman program through the Nuclear Safety department would appear to provide a good level of independence and assessment expertise. The Manager, Nuclear Safety (ombudsman) reports to the Director of Nuclear Safety in Parsippany who reports directly to the President of GPUN. This management chain is independent ofline management. Since the Director of Nuclear Safety reports to the company president, concerns about a manager or vice president can be independently evaluated. The Manager, Nuclear Safety will either investigate an issue personally or will use a member of his Independent Onsite Safety Review Group (IOSRG) staff to perform the evaluation. Third party consultants are not used. The Manager, Nuclear Safety and his IOSRG staff have received training in root cause analysis, human performance assessment, and general

: interviewing techniques. Issue resolution is tracked by the ombudsman who also makes the final decision on issue resolutio Individuals may report concerns to the ombudsman anonymously and may report them by telephone. The individual's identity is maintained anonymous to the best of the
. ombudsman's ability. Reports of issue investigations are considered confidential. A copy of this information is provided to the individual upon completion of the followup. Specific resolutions of concerns are not disseminated. The Manager, Safety Review does put out a L monthly report of department accomplishments. This report notes whether an issue was raised to the ombudsman and whether it was resolved. The issue is not described and specific resolutions of valid concerns are not publicize p
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, The licensee has only measured program effectiveness to this date by timeliness of issue resolution. Concerns are not trended. . An audit of the ombudsman program has never been performed by the licensee. A formal program assessment is now being performed by the
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corporate ombudsman. The licensee has yet to determine the frequency of future audit .2 . Performance-Based Quality Assurance Implementation Effort The inspectors assessed the licensee's continuing efforts to incorporate more performance-

- . based activities into its quality assurance (QA) audit and monitoring functions. Recent efforts have been focused on formalizing the identification and corrective action processes for performance-based QA findings and establishing a uniform approach to performance-based QA through interface with audited organizations. The inspectors reviewed performance-based implementation activities with site and corporate personnel. The inspectors assessed the efforts of the line departments in developing individual department performance indicators. The inspectors also discussed the performance-based QA implementation effort with several members of the General Office Review Board (GORB) who have been monitoring its progres NRC Inspection Report 50-219/93-09 dated July 18,1993, documented the findings of the independent Cooperative Management Audit Program (CMAP) audit of the operational QA program,- O- of the findings of the CMAP audit noted that while performance concerns were now b% discussed in QA audit reports, a formal response / corrective action / tracking L process had yet to be developed for performance-based issues. GPUN QA has been
. developing procedures to assure that significant performance-based issues are responded to and tracked accordingly. The intent is that performance-based issues be categorized similar to other QA audit findings (i.e., quality deficiency report (QDR), audit finding)

commensurate with their significance. Also under development is a formal categorization of performance concerns identified during QA monitoring activitie In parallel with the QA efforts,' the Director, Operations and Main _tenance began an effort to solicit performance indicators from the site line organizations. The guidance given to line ; management was that performance indicators be developed that were measurable and  ; provided a good basis for department self-assessment as well as QA review. The inspectors l

. reviewed the initial set of performance indicators submitted by each line organization and discussed their content with the Direc'ar, Operations and Maintenance. While some good =

performance-based indicators were p.esented, the inspectors noted that most of the suggested indicators were oriented toward department goals vice individual performance. Many of the proposed indicators _ focused more on whether a process was being implemented in accordance with established guidelines as opposed to how well the process was workin . The inspectors commented that there were few proposed indicators providing for assessment

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, of communication quality and accountability, but acknowledged that these issues would be l

' more difficult to measure. The Director, Operations and Maintenance teknowledged 0:at )

more effort was needed to develop an appropriate set of performance indicators. In particular, he noted that he was striving for an appropriately balanced set of departmental

:and individual performance indicators that represented, as much as possible, a uniform line

, organization approach to improving performance. The Director, Operations and Maintenance ' also affirmed that while discussions were being held between QA and the line organizations

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during the development of the performance indicators, QA would not be held to only assessing the agreed upon indicators. GPUN,QA personnel reiterated that the areas of their performance-based assessments would not be limited by the performance based indicators

. established by the line organizatio The inspectors discussed the progress of the performance-based QA implementation effort z - with the three members of the GORB QA Committee. The GORB QA Committee is chartered with periodically assessing the effectiveness of the GPUN QA program and presenting the results of that assessment to the GPUN President. GORB began asking questions about implementation of performance-based QA efforts about a year ago. At that time, GORB had commented that compliance-based efforts appeared to be working well and that the best option for improving overall QA effectiveness would be to explore performance-
: based assessment. GORB was also part of the pre-audit discussions with the CMAP independent audit team and recommended that they assess the progress and quality of performance-based QA assessment at Oyster Creek. The GORB members were aware of the ongoing performance indicator development effort as well as the QA efforts to formalize the performance-based assessment process. The GORB members were enthusiastic about the progress to dat Overall, the inspectors concluded that the licensee was making a concerted effort to formalize the implementation of QA performance-based assessment and develop a workable set of

_ performance indicators for the line organization. Plant management acknowledged that more effort is needed to assure that the line department-specific performance indicators are truly performance-based and that a uniform approach to improving performance is taken, wherever possible. The inspectors also concluded that GORB was supplying good oversight for the effort and was cognizant of ongoing activities.

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- Review of Previously Opened Itents (Closed) Violation 50-219/92-21-01. This violation dealt with a failure to establish a fire watch for the fire pond pump house in accordance with technical specification (TS) 3.1 Both fire diesel pumps had been taken out of service at 10:00 p.m. on October 21,1992, so that maintenance could be performed the discharge valve for fire diesel pump 1-1. This action also required that the deluge system for the fire pond pump house be rendered inoperable. ' At 12:50 a.m. on October 22,1993, the oncoming group shift supervisor (GSS)

que_stioned why a fire watch had been not established in accordance with TS and established a fire. watch shortly thereafte The licensee's' December 18,1992, violation response concurred with the notice of violation (NOV) but stated their belief that a TS change could have been approved supporting their interpretation, at the time of the event, that a fire watch should not have been necessary since the fire pumps were inoperable. The inspectors acknowledged the licensee's comment but reiterated that the decision not to post the fire watch was directly contrary to Oyster Creek TS requirements and that bypassing the formal TS change process by way of an internal TS

. interpretation was inappropriate. The licensee did not pursue a specific TS change to resolve

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L this issue since a prior TS change request had been submitted in April 1992 requesting relocation of fire protection program requirements outside the TS in accordance with NRC Generic Letter 86-10. GPUN agreed to comply with the specific statements in the TS in the interi L Oyster Creek TS Amendment No.161 was approved on February 18, 1993, that relocated the fire protection program requirements from the TS and to the Updated FSAR. Condition

- 2.C(3) was added to the Oyster Creek facility operating license requiring that the fire protection program be implemented and maintained and that program changes could be made without prior NRC approval provided they would not adversely affect the ability to achieve and maintain a safe shutdown condition in the event of a fire. The administrative controls

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< section of the TS was changed to require procedure development for and audits of the fire protection progra The inspectors reviewed the procedures associated with the fire protection program to assess
. whether the system operating conditions and action requirements formerly in the TS had been incorporated. In particular, the inspectors reviewed Procedure 101.2, " Fire Protection Program," Revision 14, dated August 8,1993, Procedure 333, " Plant Fire Protection System," Revision _43, dated August 27,1993, and Procedure 120.2, " Fire Watch Impairment Reporting and Fire Watch Instruction," Revision 10, dated September 3,199 The inspectors noted that the former TS requirements had been appropriately incorporate The inspectors also noted that the procedures did not reflect the licensee's comment in their response to the NOV regarding the concept of not needing a fire watch for equipment that was not required to be operable. The licensee responded that it was their decision not to include this concept in the procedures as a conservative measure. The licensee indicated that this concept would be applied as case-by-case basis and that fire watches would be established in the interim while the potential for removing the fire watch was being evaluated. Based on.these findings this violation is close iClosed) Violation 50-219/92-14-01. This violation dealt with failure to properly implement surveillance procedure 602.3.014, Revision 0, "Electromatic Relief Valve (EMRV) Pressure o Sensor / Pilot Valve Control Relay - Test and Calibration," on July 5,1992, causing the r ' inadvertent opening of the 'C' EMRV for about cight seconds. The inspectors reviewed the actions taken by the licensee to preclude future occurrences of this erro The inspectors reviewed the control room response and the maintenance department's initial
- root cause assessment of the technician error shortly after the event occurred (see Inspection
- Report 50-219/92-14). The two I&C technicians who went to the wrong EMRV pressure

- sensor were excluded from work on safety systems until they had completed a requalification program and received approval from I&C department supervision. The inspectors verified that the technicians had completed the specified requalification program. The technicians also conducted a training session for other I&C technicians on ways to avoid making this type of mistake. The technicians were requalified for work on safety systems on November 10,1992. ' Based on these findings, this violation is close e

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[ (Closed) Unresolved Item 50-219/92-14-02. This unresolved item dealt with the

documentation of NRC regulatory guide commitments in the FSAR. An observation from a L1987. Integrated Performance Assessment Team (IPAT) inspection noted a need for clarification of commitments to regulatory guides in the FSAR. The inspectors reviewed the current version of the Updated FSAR (Update 8, dated July 29,1993) for regulatory guide reference informatio UFSAR Section 1.8, " Conformance to NRC Regulatory Guides," has been updated with a table (Table 1.8-1) that cross references Systematic Evaluation Program (SEP) topics with applicable regulatory guides, related general design criteria (10 CFR 50, Appendix A), and the full-term operating license for Oyster Creek (NUREG-1382). The SEP evaluated the Ldesign of the Oyster Creek facility as of March 1972 against various regulatory guides promulgated up to 1973. Plant modifications since 1973 have addressed regulatory guides as part of their design. These 'other regulatory guide references have been addressed throughout the text of the FSAR. Based on these findings, this item is close (Closed) Violation 50-219/92-25-01. This violation dealt with a failure to update the FSAR

.~with information related to a 1984 plant modification of the torus suction strainers. The inspectors reviewed the licensee's response to the notice of violation and the current procedure governing changes to the FSA The l'icensee's violation response of March 12, 1993, concurred with the violation and
' indicated ~that the current FSAR update process was improved because it provided for more internal GPUN control and included a general review of each section by technically cognizant personnel prior to each update. The response noted that while the process had improved, the general section reviews may not necessarily pick up an error of this type because they do not involve system walkdowns. The response also stated that it was unlikdy that this type of error would be discovered via other initiatives such as during the preparation of a design basis document (DBD).

The inspectors reviewed procedure 1000-ADM-7320.01, " Updated FSAR Document Change Control," Revision 2, dated July 19,1991 and discussed this issue with the FSAR Administrator located in the GPUN corporate office in Parsippany, NJ. The inspectors ; concluded that the current FSAR change process was in accordance with the requirements of 10 CFR 50.71 (e) and would provide for continued improvement in FSAR conten However, the inspectors did not agree with the licensee's comment that DBDs were not likely to identify these types of errors. Specifically, the inspectors reviewed the licensee's specification for DBD development (SP900-56-010, dated March 8,1991) as well as the specific portion of the core spray system DBD (SDBD-OC-212-A) that discussed the torus suction strainers. Section 6 of SP900-56-010, " Detailed Requirements of the Design Ihsis Reconstitution Product," notes that a " list of discrepancies should be identified and corrected." A difference between a DBD identified value and an Updated FSAR stated value was given as an example of a discrepancy that should be corrected. The recent design

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discrepancy regarding blowout panels on the refueling floor was a good example of a design ' difference found during a DBD walkdown that will result in a number of changes to the UFSAR. The inspectors also noted that the core spray system DBD delineated the 1984

. torus suction strainer modificatic'1 (SDBD-OC-212-A, Section 4.6).

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 ';The inspectors reviewed the latest version of the UFSAR (Update 8,' Dated July 29,'1993)

F( and verified that Table 6.3-3 had been changed to reflect the 1984 modification of the torus ;

.*  ~ suction strainers. Based on the above findings, this violation is close , ,f  :' , EXIT MEETINGS (40500,71707)     1
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i i f ' Preliminary Inspection Findings K'

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A verbal summary of preliminary findings was provided to the senior licensee management ; WP on September 24,11993. During the inspection, licensee management was periodically

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"   notified verbally of the preliminary findings by .the resident inspectors. No written inspection *
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f material was provided to the licensee during the inspection. No proprietary information is

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R included in this repor j

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  :The inspection consisted of normai, backshift and deep backshift inspection; 32 of the direct-inspection hours were performed during backshift periods, and 8 of the hours were deep . ,
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 -. 6.2 - L Attendance at Management Meetings
[.5  The resident inspectors attended' exit meetings for other inspections conducted as follows:
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 ' Dalg :  Lead Insnector - Subject Reoort N !

EAugust 12, ~ 1993 Walker Requalification 50-219/93-17

     - Exams    j-August 20,1993 Struckmeyer _ Radiological /- 50-219/93-19  ;

Environmental  ; Monitoring , August-20[1993 . Peluso Radiological 50-219/93-20 f Effluents

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  ? August 27,1993- Eckert Radiological 50-219/93-18  :

Controls .

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 ?^t' these meetings the lead ' inspector discussed preliminary findings with senior GPUN .

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