IR 05000458/1988019

Insp Rept 50-458/88-19 on 880801-0917.Violation Noted.Major Areas Inspected:Surveillance & Maint Observation,Safety Sys Walkdown,Operational Safety Verification,Radiological Protection Observation & Security

ML20205A107
Person / Time
Site:	River Bend
Issue date:	10/14/1988
From:	Constable G, Ford E, William Jones NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION IV)
To:
Shared Package
ML20205A092	List: IR 05000458/1988019 ML20205A088 ML20205A102
References
50-458-88-19, NUDOCS 8810250391
Download: ML20205A107 (13)

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APPENDIX B U. S. NUCLEAR REGULATORY Com!ISSION REGION.IV NRC Inspection Report: 50-458/88-19 Docket: 50-458 Licensee: Culf States Utilities Company (GSU)

P. O. Box 220 St. Francisville, Louisiana 70775 Facility Name: River Bend Station (RBS)

Inspection At: River Bend Station, St. Francisville, Louisiana Inspection Conducted: August 1 through September 17, 1988 Inspectors: udd E. J. Ford, d

niof Resident Inspector V27/PP Date

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Project >ction C, Division of Reactor Projects

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W. B. Jones, Residcy Inspector

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q m h8 Date Project Section C,% Division of Reactor Projects

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Approved: c ,,,.

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/d k di L. Constable, Chief. Project Section C Date Division of Reactor Projects 8810250391 881010 PDR O ADOCK 05000458 PDC

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-2-Inspection Summary Inspection Conducted August I through September 17, 1988 (Report 50-458/88-19)

Areas Inspected: Routine, unannounced inspection of surveillance observation, maintenance observation, safety system walkdown, operational safety verification, radiological protection observation and securit Results: Within the areas inspected, one violation was identified (failure to follow surveillance test procedure, paragraph 3).

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Q 4 3 l DETAILS Persons Contacted W. J. Beck, Supervisor, Reactor Engineering E. M. Cargill, Supervisor, Radiation Programs

, *J. W. Cook, Lead Environmental Analyst, Nuclear Licensing

• J. C. Deddens, Senior Vice President, River Bend Nuclear Group R. G. Easlick, Supervisor, Radwaste

• L. A. England, Director, Nuclear Licensing A. O. Fredieu, Supervisor, Operations

• P. D. Graham, Assistant Plant Manager, Operations J. R. Hamilton, Director, Design Engineering G. K. Henry, Director, Quality Assurance Operations

• D. E. Jernigan, Instrumentation and Control Supervisor

• L. G. Johnson, Site Representative, Cajun G. R. Kimmell, Director, Quality Services

• R. J. King, Supervisor, Nuclear Licensing J. W. Leavines, Director, Field Engineering

• I. M. Malik, Supervisor, Quality Systems

• V. J. Normand, Supervisor, Administrative Services

• W. H. Odell, Manager, Administration

• T. F. Plunkett, Plant Manager

• M. F. Sankovich, Manager, Engineering J. P. Shippeit, Operations Engineer A. Soni, Supervisor, Environmental Qualification and Specification

• K. E. Suhrke, Manager, Project Management J. Venable, Assistant Operations Supervisor The NRC inspectors also interviewed additional licensec personnel during the inspection perio * Denotes those persons that attended the exit interview conducted on September 22, 198 . Plant Systems During this inspection period, the licensee experienced a hydraulic leak on the main turbine bypass system and two reactor SCRAMS from 100 percent thermal power. The licensee also identified on August 29, 1988, that the fuel building ventilation charcoal filtration system heaters would not energize in the event the fuel building emergency ventilation system actuated. This last event is described in NRC inspection report 50-458/88-2 On August 18, 1988, a hydraulic fluid leak developed on the main steam bypass valve electrohydralic (EHC) control system which required the licensee to reduce power to less than 25 percent of rated thermal powe This action was required by River Bend Station Technical ,

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Specification 3.7.9. Later the same day, the bypass valves were declared operable and power escalation initiated. Full power operation was reached on August 22, 198 Two reactor SCRAMS from 100 percent power occurred because of main turbine trips. The first reactor SCRAM occurred on August 25, 1988, when the main generator exciter brushes failed causing a loss of main generator excitation and subsequent generator and turbire trip. The second reactor SCRAM occurred on September 6,1988, when a phase to phase short developed on the normal station grounding transformer. This also resulted in a main generator and turbine trip.

l The licensee had returned the reactor to 100 percent power by the end of

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this inspection period.

I 3. Surveillance Test Observation (61726C)

l l During this inspection period, the resident inspectors observed the l perfomance of Surveillanco Test Procedures STP-511-4235, "RMS-Fuel l Building Exhaust Duct Monitoring System Sampier Flow Rate Monitor, l Quarterly CHFUNCT and 18 Month CHCAL (1RMS*FTX5A and 1RMS*FTYSA),"

l STP-110-0101, "Turbine Overspeed Protection System Weekly Operability

! Test" and reviewed the engineered safety features (ESF) actuation that l

occurred during the performance of STP-058-4501, "Containment and Drywell l Manual isolation Actuatioa Monthly Channel Functional Test."

o STP-511-4235 - This surveillance test procedure was performed on September 15, 1988, to meet the channel functional test requirements for the fuel building exhaust duct sampler flow rate monitor required to be operable at all times. The operability requirements are described in River Bend Station Technical Specification (TS) 4.3.7.11 Table 4.3.7.11-1.3.e. The instrumentation and control (l&C)

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technicians perfoming the test were properly signed into the test

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procedure and received semission from the control operating l

foreman (C0F) prior to )eginning the test. Lifted leads and jumpers

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we rt. controlled in accordance with General Maintenance l Proceiure GMP-0042, "Circuit Testing and Lifted Leads and Jumpers."

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The coapleted test results were subsequently reviewed and accepted by the C0 o STP-110-01')1 - This surveillance test was performed on September 15 B88, with the reactor at 75 percent power to satisfy TS 4.3.8.2.a by cycling each high pressure turbine stop valve, high pressure turbine l

control valve, low pressure turbine intermediate stop valve and low l pressure turbine intercept valyc. During the perfomance of thit l

test, turbine control valve Number 4 did not fast close nor was a half SCRAM receive The licensee subsequently declared the valve inoperable and inserted a half SCRAM in the applicable channel as required by TS 3.3.1-1.M with reactor power greater than 40 percen TS 3.3.8 was also entered reqairing that the stop valve in the same l

high pressure lead be maintained operable. It was later identified i l

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~t hat TS 3.3.4.2 was also applicable. This TS requires that an end of cycle recirculating pump trip (E0C-RPT) be inserted into the applicable channel. The required jumper could not be installed prior to expiration of the one-hour action statement, requiring the licensee to enter TS'3.0.3 for 10 minutes. It was later determined that a test limit switch was not picking up properly and that the valve actually was operable. This event was discussed with the licensee. ,It was learned that each STP lists each of the applicable TS that the licensee is proving operable by the surveillance, however'

this does not always include all the applicable TS for the specific equipment. ?n this case, the operations department proves operability of the overspeed protection and RPS logic however the E0C-RPT surveillance is an I&C surveillance and thus not listed in the referenced TS. The licensee plans to provide the shift supervisors and control operating foremen with a means to cross reference all applicable TS requirements for equipment failures, o STP-058-4501 - This surveillance was perfonned on August 15,1988, to perform a monthly functional test of the nuclear steam supply shutoff system (NSSSS) manual switches B21H-S25A, B, C, and D as required by TS 4.3.2.1, Table 4.3.2.1.- During the performance of this test, the I&C technicians initiated preparations to test the "C" manual NSSSS logic prior to completing testing of the "B" manual NSSS Section 7.2 "Inboard Isolation Manual Initiation Channel "B" ,

(B21H-S258)" requires that this channel be tested and restored to its !

normal lineup prior to proceeding with Section 7.3, "Inboard Isolation Manual Initiation Channel "C" (B21H-S25C)." This is accorrplished through sequential signoff steps and no permission is granted in the procedure to deviate from the sequential steps. The licensee's Administration Procedure ADM-0003, "Development, Control and Use of Procedures," Revision 14, paragraph 6.5, requires in part that procedures shall be present and referred to while the task is ,

being performed for extensive or complex jobs where reliance on memory cannot be trusted. Unless otherwise specified, steps in a procedure shall be performed sequentially. This failure to complete '

all the steps in Section 7.2 of this procedure, prior to initiating Section 7.3. was identified by the resident inspectors as a potential violation (458/8819-01). This failure to com)1y with the procedure resulted in an ESF actuation which isolated t1e reactor water cleanup system, 4. Maintenance Observation (62703C) ]

During this inspection period, the resident inspectors observed corrective maintenance activities perfonned under maintenance work order (MWO) R116254 and reviewed the engineering safety features (ESF)

activatior. that occurred during the performance of preventive maintenance (PM) activity MWO PS20568, o MWO R116254 - This MWOR was initiated on September 12, 1988, to repair a ground fault indication on the standby service water valve

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SWP*M0VF55 The requirements of TS 3.7.1.1 were initiated which require restoration within 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> or be in not shut down within the next 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> and cold shut down within the next 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />. The TS requirements were documented as limiting condition for operation 88-319. The valve actuator was replaced under this MWOR and a post maintenance test conducted. The inservice inspection stroke times were verified acceptable utilizing STP-256-3302. The system was restored to operable status on September 13, 1988, o MWO P520568 - This PM was performed on August 27, 1988, to change the filter paper on the fuel building airborne radiation monitor 1RMS*RE58. During the performance of this PM, the I&C technician l lifted a lead from cabinet RMS-CAB 5B instead of cabinet CIJB as l specified in the PM. This initiated the fuel building emergency ventilation system. The I&C technician had been trained on non-ESF radiation monitors which have only one cabinet associated with the monitor. The I&C technicians were adhering to General Naintenance Procedure GMP-0042, "Circuit Testing and Lifted Leads and Jumpers" when the incorrect lead was lifted. The licensee has completed the

, 18C technician training on ESF radiation monitors and discussed this l event with the fcreman emphasizing the importance of ensuring an individual is completely trained on a system before he begins wor The cabinets are being relabeled to more clearly identify the correct cabinet and the affected leads will be uniquely identifie Because inadequate training has not been indicative of the licensee's training program and prompt corrective actions were initiated through the corrective action program as identified in Condition Report 88-0673, this event is viewed as isolated and no violation will be issue . Safety System Walkdown (71710C)

During this inspection period, the resident inspector performed a walkdown l of the standby gas treatment system (GTS) with the plant in operational condition 1. Two independent GTS divisions are required by River Bend Station Technical Specification (TS) 3.6.1.9 and TS 3.6.5.4 to be operable l

in operational conditions 1, 2, and 3. The GTS is designed to limit I fission product airborne release from the primary containment and i auxiliary building following accident conditions and to assure that I off-site exposure is within 10 CFR 100 limits. The GTS walkdown was l performed utilizing engineering piping and instrumentation diagram System 257, "Standby Gas Treatment," PID-27-15A, Revision 9. The walkdown consisted of inspector observation of accessible component and damper j condition, including rubberized boot integrity, air line connections and a ,

hand over hand inspection of associated instrumentation. Those GTS dampers which were inaccessible will be verified when plant conditions ,

pemi t. Review of the control board lineup did not reveal any conditions

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i which would adversely affect GTS operability. The inspector also noted '

i that during inadvertent actuation of the GTS during this report period the

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i ' system aligned and operated properly. Station operating procedure, I

50P-0043, Revision 4. "Standby Gas Treatment System was reviewed against PID-27-15A for accuracy and general workabilit No violations or deviations were identified in this area of inspection.

l l Operational Safety Verification (71707C)

The resident inspectors (RIs) observed operational activities throughout

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the inspection period and closely monitored operational events. Control l room acticities and conduct were generally observed to be well controlled.

! Proper control room staffing was maintained and access-to the control room I

operational areas was controlled. Selected shift turnover meetings were observed and it was found that information concerning plant status was being adequately covered. An event involving mispositioning of the fuel building ventilation charcoal filtration heater breakers on the main control board was identified by the licensee on August 2-9, 1988. This

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event is described in NRC inspection report 458/88-22.

l System walkdowns of the "A" and "C" low pressure coolant injectwn systems were conducted to verify major flow path alignments for operability. A '

detailed system walkdown of the standby gas treatment system was also conducted. The results of this walkdown are given in paragraph 5 of this report.

l The resident inspectors also reviewed licensee actions on operational I

events and potential problems. The results of selected items are l described below: Reactor Shutdoens During this instection period, there were two unplanned reactor i shutdowns. The details cf these events are discussed below:

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o Main Generator Exciter Brush Failure: On August 25, 1988, with

! the plant at 100 percent power, a main generator trip occurred because of a loss of excitation resulting in a main turbine trip. A reactor SCRAM was then initiated on the turbine control valve fast closure signal with turbine first stage pressure indicating greater than 40 percent power. Immediately following the generator trip, the non-safety related switch gear INNS-SWG1A failed to fast or slow transfer from the normal station transformer ISTX-XNS1C to preferred station transfonner 1RTX-XSR10. This resulted in a loss of power to the Division III, E22*S004, safety-related bus. The Division III emergency diesel generator subsequently started and the output breaker closed onto the bus within the required 10 seconds. The f failure to fast or slow transfer to preferred station transformer 1RTX-XSRIC also caused a loss of turbine plant component cooling water. This resulted in a loss of cooling water to the instrument air compressors and their subsequent t . . - - - - _ _ _ _ _ _ _ _ _

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tripping because of over heating. A false vessel water level 2 (approximately 120 inches above top of active fuel) signal was generated during the reactor SCRAM resulting in initiation of the Division III high pressure core spray (HPCS) system and the reactor core isolation cooling (RCIC) system. Approximately one hour following the reactor SCRAM, it was identified that the HPCS injection piping upstream of the injection valve was experiencing abnormally high temperature Prior to the generator trip, the licensee had identified that arcing was occurring at the generator exciter brushe Preparations were underway to replace the brushes when the loss of exciter field occurred resulting in the main generator tri An apparent decrease in brush spring tension on the collector rings, because of brush wear, caused the arcing and subsequent loss of exciter field. The licensee has reviewed their preventive maintenance (PM) tasks for brush replacement and determined that the brushes shall be replaced prior to the brush reaching the end of the sight viewing band. This is more conservative than the vendor recommendations which had been used to develop the existing PM. The viewing band simply allows for monitoring of brush wear. The brushes should retain sufficient spring tension prior to reaching the end of the viewing band to prevent reoccurrenc During the transient which occurred concurrent with the reactor SCRAM, the normal station transformer 1STX-XNSIC failed to fast or slow transfer to preferred station transformer 1RTX-XSRI The nomal station transfomer 1STX-XNSIC carries the loads for the non-safety related bus INf;S-SWG1A when the main generator is on line. The failure to transfer caused a loss of power to INNS-SWG1A which feeds the safety-related HPCS bus 1E22*S004 The 1E22*S004 bus isolated and the associated Division III emergency diesel generator started and carried the bus loads as expected. The fast transfer did not occur because the decreasing generator output voltage caused a decreased voltage at the Fancy Point Substation. The decreased voltage caused an under-voltage relay (59R-1NNSA08) to deenergize. This relay must be energized for either the fast or slow transfer to occu ,

Prior to the 59 relay, as it is called, reenergizing, a time 1 delay relay deenergized as expected preventing the fast transfer from ISTK-XNS1C to 1RTX-XSR1C. In order for a slow transfer to occur, both under-voltage relays (27-1-1NNSA17 and 27-2-1NNSA17)

must actuate. However, only one of the two 27 relays actuated, thus preventing the slow transfer. The relay appears to not have actuated because of corrosion of the silver contacts. The PMs for these 27 relays had been set at the recomended 24 months, and have now been revised to a 6 month frequenc An engineering evaluation is also being perfomed to detemine if a more reliable under-voltage relay may be installed. The i 27 relays which wre suspected not to have operated properly

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have been replaced. All remaining 27 relays used in this application were verified to be operable prior to the reactor startup on August 28, 1988. The licensee's review of applications for this relay (Westinghouse KV-1) did not reveal any instances where these relays are used in safety-related equipmen When INNS-SWG1A lost power, the two running turbine plant component cooling water (CCS) system pumps ICCS-PIA and 1C tripped. Although CCS pump 1CCS-PIB automatically started on decreasing system pressure, it was not sufficient to maintain proper cooling to the instrument air system (IAS) compressor The three IAS compressors subsequently tripped on high temperatures. IAS pressure dropped approximately 40 psig down to 80 psig in 10 minutes. At the initiation of this event, several expected air operated damper (A00) activations occurred because of the loss of the Division I reactor protection system (RPS) bus. These A00 activations occurred on the fuel building ventilation system, standby gas treatment system and annulus mixing. Af ter approximately 10 minutes, the IAS compressors were restarted with the required CCS pumps operating to maintain proper IAS compressor temperatures. The licensee reviewed the setpoint for isolation of the service air system (PAS) from the IAS and found the setpoint to be approximately 5 ps1 below the lower limit setpoint. The isolation and reset setpoints were subsequently calibrated to within the desired limits. No abnormal valve or damper actuations occurred because of the decreased IAS pressure. The licensee has established a task l force to review the IAS design and the systens response to !

events such as the one described above. This task force was )

established through the office of the Senior Vice President, River Bend Station Nuclear Group. This task force review will include previous events, significant operating event reports and i NRC Generic Letter 88-1 j

The reactor SCRAM was initiated by the main turbine control I valve fast closure signal. The steam bypass valves responded as !

required , however the resulting pressure transient on the reactor vessel caused five safety relief valv0s to activate in their low-low set function to control pressure initially. The peak pressure reached was approximately 1115 psig which is expected for the above transient conditions. The resulting pressure transient is initially detected in the upper region of the reactor vessel. The pressure wave then travels down through the reactor core and annulus area compressing the voids that are present. This results in a normal indicated water level decrease to approximately 10 inches on the narrow range instruments. Normal operating vessel level is approximately 34 inches narrow range. During this transient however, vessel level appeared to have spiked te a low of .43 inches on the wide range instruments, which actuated the vessel water Level 2 HPCS

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and RCIC systems. This level indication lasted less than 300 milliseconds for the entire duration of the spike. The actuation of the HPCS system and subsequent injection of system water required the licensee to enter a notice of unusual even Within 30 seconds, the injection was terminated when the high vessel water level setpoint, Level 8, was reached tripping the main feedpumps, and closing the RCIC steam supply and HPCS injection valve The licensee subsequently initiated an investigation to determine why the Level 2 initiation occurred. Review of the vessel level transmitter instrument taps on the reactor vessel reveals that the pressure wave would first be felt at the reference leg which taps in on the upper region of the vesse The increased pressure on the reference leg would cause the level transmitter to indicate a lower water level than actually existed until the pressure wave reached the variable instrument tap lower in the vessel. The instruments used for the emergency core cooling systems (ECCS) are the Rosemount 1154 model. This 1154 delta pressure model does not have a dampening circuit which would slow the response time down. The original purchase order specified the needed maximum response time, however, subsequent testing has revealed that the response time is faster than is needed. No limit on minimum response time had been established. The reactor protection system (RPS) utilizes an 1152 model which does have the dampening circuit. The 1152 models indicated the expected vessel levels throughout the transient, where as the 1154 model initially spiked low for approximately 300 milliseconds then paralleled the 1152 respons The licensee has concluded that the 1154 transmitters are responding to the initial pressure transient rather than actual vessel water level. This conclusion is supported by similar occurrences at Perrs/ Nuclear Station which has observed similar responses from the undampened Rosemount 1153 model. The licensee is presently reviewing a modification to the trip unit to dampen out the initial signal seen on the 1154 transmitter The licensee is planning on implementing a modification to the 1154 transmitter which should be available from Rosemount after January 1989. The modification will add a dampening circuit at the transmitter which meets the environmental qualification requirements for post loss of coolant accident condition Approximately 45 minutes after the HPCS system injection was terminated into the reactor vessel and 20 minutes after securing the HPCS pump, it was noted that the injection pump temperatures upstream of the injection valve,1E22*MOVF004, were in excess of 212'F. A later temperature profile developed for the HPCS injection piping shows that temperatures near the injection valve on the 141 foot elevation may have exceeded 500*F and

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275*F at the 114 foot elevation. This temperature profile was developed from actual temperature readings taken on the HPCS pipe 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> after the event and analyzed in engineering calculation G13.18.2.0*14-0. The licensee is presently investigating the cause of the reactor water intrusion upstream of the 1E22*MOVF004 valve. Prior to the reactor startup on August 28, 1988, the licensee completed their technical justification for continued operability of the HPCS syste This justification is batad on the following: Civil / Structural calculations conclude that stresses in HPCS piping did not exceed allowable stresses and that the piping can be cycled through at least one more transient of the same type without compromising system integrit . Volumetric and surface examinations were performed on the welds which experienced the highest stresses and no unacceptable indications were identifie ,

, A walkdoun of all accessible supports revealed no damage, o Loss of Normal Station Transformer: On September 6, 1988, a

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main generator trip occurred when a phase to phase short  !

developed on a nonnal station grounding transformer. The phase to phase short resulted from a cat coming in contact with two of

the high side phase leads from the normal station transformer to

< the grounding transfer. This condition was detected by the Differential Relays 87S1-A, B and C, which tripped the main generator 86 lockout relay. This resulted in the main turbine

trip with turbine control valve fast closure and reactor SCRA All normal to preferred station transformer fast transfers occurred as expected. A low indicated vessel water level was again seen during this transient on the Rosemount 1154 level transmitters which resulted in the HPCS and RCIC systems initiating. A notice of unusual event was declared because of the HPCS injection. Actual vessel level appears to have decreased to approximately 10 inches on the narrow range instruments. Review of the 1154 transmitter response to the pressure transient indicates an almost identical response to t

l that observed during the previous reactor SCRAM from turbine j control valve fast closure while at 100 percent powe Prior to shutting down the HPCS pump, station personnel were sent to the

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injection valve to monitor HPCS pipe temperature after the HPCS

pump was stopped. No abnortnal temperature increases were noted following this .ctuatio Potential Degradation of Secondary Containment:

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i On August 29, 1988, with the reactor in operational condition 3 the licensee identified that the concrete roof plugs forming part of the

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secondary containment boundary were missing the required retention hardwa re. The retention hardware is-required to retain the concrete plugs in place in the event a tornado were to pass over secondary containment. Upon discovery of the missing retention hardware, the licensee initiated a limiting condition of operation (LCO) as required by River Bend Station Technical Specifications Section 3.6.5.1 which requires that secondary containment be restored within 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> or be in at least cold shut down within the subsequent 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> with the reactor in operational condition 3. The required retention bolts were installed within 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> thus averting the requirement to place the reactor in cold shut down. This condition is being reported as a condition of operation prohibited by the River Bend Station Technical Specifications pursuant to 10 CFR 50.73 (a)(2)(1). The condition was identified during an inspection of concrete roof plugs as followup corrective actions to licensee event report LER 88-01 Emergency Notification System: During this inspection period, the licensee notified the realdent inspector that they would not be able to complete work on the computer hardware and software modifications for the emergency sirens by October 31, 1988. The licensee's actions to reduce the number of inadvertant emergency siren actuations was originally identified as open item 458/8812-01. The licensee has completed all the modifications described in the open item with the exception of the computer hardware and sof tware modification The resident inspector will continue to monitor the licensee's progress in this are No violations or deviations were identified in this area of the inspectio < Radiological Protection Observations (71709)

The NRC inspectors verified that selected activities of the licensee's radiological protection program were implemented in conformance with the River Bend Station Technical Specifications and licensee approved procedures. Radiation work permits (RWP) contained appropriate information to ensure that work could be perforced in a safe and controlled manner. Radiation and contaminated aress were properly posted and controlled. Personnel performing work authorized by a specific RWP were questioned concerning the requirements and limitations given in the RW No violations or deviations were identified in this area of the inspectio . Security (71881)

The resident inspectors observed security activities during this inspection period. The activities observed included a physical search of licensee personnel and packages prior to allowing access into the

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protected area. Compensatory posts were observed to be in place and attentive when intrusion detection equipment was degraded. Security officer response to vital area door alarms was prompt. The licensee has completed modifications to the access corridor for personnel entering into the protected area. This modification further ensures that prohibited materials will be deleted prior to being brought into the protected are No violations or deviations were identified in this area of the inspectio . Exit Interview An exit interview was conducted on September 22, 1988, with licensee representatives (identified in paragraph 1). During this review the RI reviewed the scope and findings of the inspectio l f

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