IR 05000454/1989016

Safety Insp Repts 50-454/89-16 & 50-455/89-18 on 890701-0819.Violations Noted.Major Areas Inspected:Plant Matl Condition,Operational Safety,Mud in Essential Svc Water Sys,Security & Discrepancy Records

ML20246M625
Person / Time
Site:	Byron
Issue date:	08/30/1989
From:	Hinds J NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION III)
To:
Shared Package
ML20246M600	List: IR 05000454/1989016 ML20246M592 ML20246M609
References
50-454-89-16, 50-455-89-18, IEB-87-002, IEB-87-2, NUDOCS 8909070212
Download: ML20246M625 (12)

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U. S. NUCLEAR REGULATORY COMMISSION

REGION III

Report Nos. 50-454/89016(DRP); 50-455/89018(DRP)

Docket Nos. 50-454; 50-455 License Hos. NPF-37; NPF-66 Licensee: Commonwealth Edison Company Post Office Box 767-Chicago, IL 60690 Facility Name: Byron Station, Units 1 and 2 Inspection At: Byron Station, Byron, Illinois Inspection Conducted: July 1 through August 19, 1989 Inspectors: W. J. Kropp R. N. Sutphin N. V. Gilles D. R. Calhoun Approved'By:

fA Cfluf /GA-J." M. Hinds, Jr., Chief S-30-67 Reactor Projects Section lA Date Inspection Summary Inspection from July 1 through August 19, 1989 (Report Nos. 50-454/89016(DRP);

50-455/89018(DRP))

Areas Inspected: 1. Routine, unannounced safety inspection by the resident inspectors of licensee action on previous inspection findings; operational safety; plant material condition; event follcw-up; mud in Essential Service Water System; maintenance / surveillance activities; backlog; discrepancy records; self-assessment capabilities; follow-up on Headquarters request (TI 2500/27); engineering and technical support; security; and meeting . SIMS issue status for Units 1 and 2: Closed BL-87-02 Results: Of the 11 areas inspected, no violations or deviations were identified in 10 areas; 1 violation was identified in the following area:

(operational safety - paragraph 3.a). Two unresolved items were identified

.that pertained to the power source for valves and for EQ solenoids in the hydrogen monitoring system W !as!! ES$g4 a

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. o DETAILS . Persons Contacted Commonwealth Edison Company

• 1. R. Pleniewicz, Station Manager

• 1. G. Schwartz, Production Superintendent

• 1. R. Ward, Technical Superintendent

• 1. J. Kudalis, Service Director D. Brindle, Operating Engineer, Administration T. Didier, Operating Engineer, Unit 0 T. Gierich, Operating Engineer, Unit 2

• T. Higgins, Assistant Superintendent, Operating J. Schrock, Operating Engineer, Unit 1

• D. St. Clair,-Assistant Superintendent, Work Planning

• T. Tulon, Assistant Superintendent, Maintenance l

1. D. Winchester, Quality Assurance Superintendent

1. D. Wozniak, ENC Project Manager

• 1. E. Zittle, Regulatory Assurance Staff The inspector also contacted and interviewed other licensee and contractor personnel during the course of this inspectio # Denotes those present during the management meeting on }uly 28, 198 * Denotes those present during the exit interview on August 21, 198 . Action on Previous Inspection findings (92701 & 92702)  ! (Closed) Unresolved Item (454/89014-02(DRP); 455/89016-02(DRP)):

Inadequate post-maintenance testing identified as a cause for LER 455/89005 and other recent events. See Section 4.a of this report-for details on the closure of this Unresolved Ite (Closed) Open Item (454/89014-01(DRP); 455/89016-01(DRP)): The issue of periodically testing the Remote Shutdown Panel Safety Injection feature in " local" appeared inconclusive as to specific or desired test requirements. See Section 6 for details on the i closure of this Open Ite . Plant Operations Unit 1 operated at power levels up to 100% for the entire report perio ;

Unit 2 operated at power levels up to 90% for the entire report perio Operational Safety (71707) l The inspectors observed control room operation, reviewed applicable logs and conducted discussions with control room operators during l

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July and August, 1989. Based on discussions and observations, the inspectors ascertained that the operators were alert; cognizant and

attentive-to changes:in piant conditions; and took prompt. action e -when appropriate. The inspectors verified the operability.of

' selected lemere ncy systems, reviewed tagout records, and verified I

the proper return to service of affected components.

p The inspectors-verified by' observation and direct interviews'that the physical security plan was. implemented in accordance with the station security plan.

L The observed facility operations were verified to be in'accordance.

L with the requirements established under Technical Specifications, e 10 CFR, and administrative procedures except during a walkdown of-the Unit 1 Main Control Boards, when inspectors'noted that mini-flow recirculation valve, 1CV8110, for the 1B centrifuga ..

charging (CV). pump.was closed. The design of the CV system included two mini-flow valves in series for sach CV pump. For the 1B CV' pump, the mini-flow valves were the motor operated valve, 1CV8110, and solenoid operated valve', 1;V8114. The purpose of 1CV8114 was to protect the 1B CV pump from deadheading during certain. abnormal plant events. This protection was automatic upon a Safety Injection (SI) signal when valve 1CV8114 would open or close automatically, dependent on reactor coolant system (RCS) pressur However, with valve 1CV8110 closed, the automatic protection feature of valve-1CV8114 depended on operator actions to open 1CV8110 during an SI event. The inspectors identified the following concerns:

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(1) Updated Final Safety Analysis Report (UFSAR), Section 6.3, states that no manual actions were required of the operator

'for proper; operation of the ECCS during cold leg injectio With valve 1CV8110 closed, operator action was required for proper operation of the 1B CV pump during cold leg injectio Therefore, since the licensee operated from at least June 21 to June 30, 1989 with 1CV8110 closed, a 50.59 review in-accordance with procedure BAP 1210-5, "10 CFR 50.59 Safety Evaluation" Revision 6, was required as the plant was not operated as described in the UFSA (2) Procedure BAP 340-2, " Initiation and Use of Systems Lineups (Mechanical and Electrical)", Revision 23, required that a Abnormal Valve Position Log sheet be completed when a valve was not in a position consistent with the. valve lineup sheet (M-1)

for. longer than one shift, unless~the valve was identified on-a Out of Service (005) tag or repositioned for a surveillanc Since valve 1CV8110 was not 00S or repositioned for a surveillance, e Abnormal Valve Position Log sheet was require No Abnormal Valve Position tog sheet was completed and reviewed by the cognizant shift personnel. However, the valve's position was documented as " closed" on the Shift Turnover Sheets.

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(3) The licensee has not yet identified the specific cause(s) of not maintaining pressurizer level with 120 gpm letdown in a normal CV system lineup. The licensee has requested Westinghouse to assist in the identification of the caus The inspectors were concerned that plant management had not aggressively pursued a technical resolution to the problem of maintaining pressurizer level with 120 gpm letdown until the

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plant condition (lCV8110 closed) was questioned by the inspector The failure to perform a 50.59 review and to complete an Abnormal Valve Position Log sheet are examples of not following procedures and is considered a. violation of 10 CFR 50, Appendix B, Criterion The licensee initiated immediate corrective action that included:

(1) opening valve 1CV8110 and operating the Unit 1 CV system in accordance with applicable requirements (2) ensuring licensed operators were aware of the importance to comply with the requirements for Abnormal Valve Log Sheets, and (3) requested a 50.59 review by Westinghouse for operating the CV system with 1CV8110 close (454/89016-01a) Current Material Condition (71707)

The inspectors performed general plant as well as selected system and component walkdowns to assess the general and specific material condition of the plant, to verify that Nuclear Work Requests (NWRs)

had been initiated fnr identified equipment problems, and to evaluate housekeepin Walkdowns included an assessment of the buildings, components, and systems for proper identification and tagging, accessibility, fire and security door integrity, scaffolding, radiological controls, and any unusual conditions. Unusual conditions included but were not limited to water, oil or other liquids on the floor or equipment; indications of leakage through ceiling, walls or floors; loose insulation; corrosion; excessive noise; unusual temperatures; and abnormal ventilation and lighting. Results were as follows:

(1) Several valves and valve actuators were noted leaking with no NWR initiate (2) Two hangers in the overhead on the 369' Elevation in the Turbine Building, one on a radwaste line and the other on a Unit 2 condensate header, appeared to have hardware missing or had l moved from the original position. Subsequent investigation by the licensee identified that other hangers on the radwaste line also had various deficiencies. Licensee engineering and operations personnel initiated action to assess the situation for determination of possible cause. The licensee identified the need for further training of Equipment Operators and Attendants to ensure attention was focused on all aspects of

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the plant during rounds which included the material condition of the plant's pipe hanger (3) Clothes and hard hats were hung on an instrument rack at a change out area outside the Unit 1 CV positive displacement pump room.

E (4) No Caution Tag was placed on the controller for the Unit lA Steam Generator Power Operated Relief Valve (PORV) located at the Remote Shutdown Panel (RSP). The controller for 1M5018A had a Caution Tag on the Main Control Board which identified that block valve, 1MS019A, for the 1A PORV was closed. A similar occurrence on the Unit 2D PORV was reported in Inspection Report 50-455/89016. Procedure BAP 330-6, Revision 2, " Caution Card Procedure" states that Caution Tags were designed to call attention to temporary information relating to equipment performance that was not normal. Failure to place a Caution Tag on the 1A PORV controller on the RSP is another example of failure to follow procedures and is considered a violation of 10 CFR 50, Appendix B, Criterion V. The licensee's immediate corrective action included placement of a. Caution Tag at RSP and initiation of a revision to BAP 330-6 to emphasize the requirement for Caution Tags on the RSP, when require (454/88016-Olb)

The inspectors concluded that increased management attention was required to ensure that hardware problems, such as leaks, were identified on NWRs. Based on the number of leaks, housekeeping and the licensee's response to the pipe hanger deficiencies, the inspectors concluded that during this report period the overall material condition of the plant appeared above average. Plant management was responsive to the inspectors' concern Onsite Event Follow-up (93702)

The inspectors performed reviews of licensee activities associated with the following two events. The events pertained to tube leakage in the Unit "lC" Steam Generator (SG) and a spent fuel leakage of approximately 1 gp (1) On July 25, 1989, the licensee identified a "lC" SG tube leakage of approximately 40 gpd. The Technical Specification (TS) limit was 500 gpd. Indication of the leakage disappeared with subsequent '"lC" SG samples on July 27, 1989. The "lC" SG has a history of leakage that disappears in a short period of time. The licensee suspects a crevice leak that would be difficult to detect during tube inspections. The licensee had increased sampling of the "lC" SG to shiftly (TS requires every 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br />) and placed a N-16 monitor where the "1C" SG main steam line exits containment. The licensee subsequently decreased the frequency of samples on the "1C" SG when the

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Lleakage disappeared; however, the N-16' monitor was maintaine to provide.shiftly monitoring.for.several days as a'

conservative measur '(2) On July 27,1989,~ spent fuel pool leakage was identified by a Equipment Attendant (EA) during rounds. The licensee determined that the' leakage was'approximately 1 opti. .The spent fuel. pool level was 1 1/2 feet above the TS limit of 23 feet:

above=the top of the spent fuel assemblies. The~11censee'had recently removed'16 bolts from several fuel racks for installation of high density fuel racks. The 16 bolts were

re-installed and the leakage stopped. However, further testin and inspections which included removal of the same 16 bolts, could not recreate the leak. ~The licensee continued with the investigation that-included. vacuum box testing. On August 8, 1989, the licensee identified.the source of the leakage as a defect in the liner that was approximately 1/64" x 1/4". When the defect was cleared of-debris the leakage was determined to be approximately 8 gph. The licensee believes the defect was

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from original fabrication / installation. The licensee initiated actions to: repair the defec The inspectors concluded that for the above two events, the licensee was aggressive in the pursuit of resolution or identification of potential' problems prior to reaching TS limits. Also, the:

inspectors considered the identification of a 1 gph leakage in the spent fuel pool by the EA as an example of attentiveness to detail on rounds.- However, the licensee needs to further enhance the effectiveness of rounds by EA and Equipment Operators (E0) by emphasizing.that other areas of the plant,.not addressed by logs,

.need attentio d. . Mud Build-up in Essential Service Water Lines (71707)

This issue was discussed in Inspection Report Nos. 50-454/89010; 50-455/89012. The licensee had committed to identify any stagnant Essential Service Water (ESW) lines,-that were susceptible to mud build-up. The licensee identified several ESW lines that were stagnant at least part of.the time. The licensee plans to perform flushing of the majority of these lines approximately every six months. Individual flushing frequencies for these lines will be-determined on a case by case basis, based on future experienc Some of the identified lines had no flow a portion of the time [ dual _ train systems with one train in operation at a time] and the licensee considered this sufficient to prevent mud build-u Based on the -iicensee's identification of other ESW lines susceptible to mud build-up and the periodic flushing of these lines, the inspectors have no further concerns at this tim One violation with two examples was identified.

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. . Maintenance / Surveillance (61726 & 62703) Activities Station maintenance and surveillance activities of the safety-related systems and components listed below were observed or reviewed to determine that the activities were conducted in accordance with approved procedures, regulatory guides, and industry codes or standards, and in conformance with Technical Specification Maintenance

• Nuclear Work Request (NWR) B66533 - Adjustment of 1A Diesel Generator (DG) fuel linkag * NWR 867043 - Troubleshoot fuel rack control system for lA D * NWR B68316 - Repair of valve 1PS230 * NWR B68318 - Repair of valve 1PS228 Surveillance

• 180S 3.2.1-842, "ESFAS INSTRUMENTATION SLAVE RELAY SURVEILLANCE (Train A Containment Isolation Phase A-K607)."

• 1805 3.2.1-991, "ESFAS Instrumentation Slave Relay Surveillance (Train B FW Pump Trip, SG level HI-HI-K621)."

• IBOS 3.2.1-920 "ESFAS Instrumentation Slave Relay Surveillance (Train A Feedwater Isolation. HI-HI SG level-K638)."

• 2B05 3.2.1-851, "ESFAS Instrumentation Slave Relay Test."

• 2B05 8.1.1.2.A-1, "2A DG Operability."

• 2B05 8.3.1-1, "ESF Onsite Power Distribution."

The following items were considered during this review: the limiting conditions for operation were met while affected components or systems were removed from and restored to service; approvals were obtained prior to initiating work or testing; quality control records were maintained; radiological and fire prevention controls were accomplished in accordance with approved

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procedures; test instrumentation was within its calibration interval; functional testing and/or calibrations were performed prior to returning components or systems to service; test results

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conformed with Technical Specifications and procedural requirements and viere reviewed by personnel other than the individual directing the test; any deficiencies identified during the testing were properly documented, reviewed, and resolved by appropriate manage-l ment personnel. The following concerns were identified:

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('l) LER 455/89005 identified that the 1A Diesel Generator (DG)

failed to load to 5500 KW within 60 seconds. The event was discussed in Inspection Report Nos. 50-454/89010; 50-455/8901 The LER identified the causes as inadequacies in maintenance procedures and post-maintenance testing. The inability to reach a load of 5500 KW within 60 seconds was the result of maintenance performed on the "Bimba" shutdown cylinder. The (-

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i inspectors discussed the' event with Technical Staff engineers and a Diesel Generator vendor representative. The inspectors also reviewed the maintenance work history that pertained to previous repair / replacement of the "Bimba" cylinder. Based on discussions with the vendor representative and the review of past work history, the replacement of the cylinder should not require a fuel rack "zero" and " span" adjustment. However, to preclude repetition of the event discussed in LER 455/89005, the licensee established controls to check the fuel rack zero and span adjustment when the "Bimba" cylinder is replace The inspectors did identify a concern with the Vendor Technical Information Program (VTIP) that was not identified by the licensee in LER 50-455/89005. The maintenance staff had a detailed procedure for set-up of the DG governor that was not in the VTIP. The licensee stated a revision to LER 455/89005 will be initiated that identifies this concern and the appropriate corrective actio (2) Two concerns were identified during the review of maintenance and surveillance activities that pertained to the hydrogen monitor suction valves. For further details see Section and 6.b of this repor Backlog The inspectors reviewed the licensee's backlog of non-outage NWRs to determine if maintenance was accomplished. The inspectors selected three NWRs from a computer listing of the licensee's backlog as of July 3, 1989. .The NWRs were evaluated for safety impact of deferrals, and causes such as lack of personnel, lack of trained / qualified personnel, lack of parts or engineering suppor The three NWRs reviewed were:

B54997 - 18 AFW pump took 4 cranks to star B56588 - Position Indication for valve ICV 8114 not properly functionin B65783 - Limitorque Gearcase for valve 1S188048 had mixed grease at a 20:1 rati No violations or deviations were identifie . Safety Assessment / Quality V. verification (35502,40500,40704) Licensee Discrepancy Record (35502)

The inspectors reviewed Discrepancy Records (DR) 06-87-0312 and 06-07-0313 for proper resolution and adequate corrective action The DRs pertained to non-safety related instruments that were connected to Class IE circuits without isolation devices. To verify the effectiveness of the corrective action, the inspectors selected four instruments identified on the DRs and reviewed the i specific isolation methods. The instruments selected were two flow transmitters (IFT-0522 and 0523) in the main steam line and 3 i

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y two pressure switches (IPS-CV032 and CV033) utilized in the charging system. The inspectors reviewed.Sargent & Lundy (S&L) Interface Review Reports (IRR) for each of the selected instruments. The inspectors determined that S&Ls analysis, stated in the IRRs, was appropriate and had coneidered the-necessary salient points to ensure operability of the instrument Licensee's Self-Assessment Capability (40500)

The inspectors reviewed the Quality Assurance (QA). surveillance and audit schedules to verify proper implementation. QA had performed more than the scheduled number.of audits and surveillance. The inspectors reviewed several audits and surveillance and no discrepancies were identified. Audit and surveillance findings were properly identified and tracked; identified to management for proper resolution; corrective actions were adequate and timely;.and follow-up audit activities were performed to verify effectiveness of corrective actio Corrective action that pertained to training was reviewed by the inspectors to verify the appropriate personnel were traine The inspectors also accompanied a QA auditor during the performance of an audit on Technical Specification Surveillance items. The inspectors ascertained that the auditor implemented the requirements of Memorandum #3, " Technical Specifications Auditing, Revision 3."

The inspectors observed the interface between QA and plant personnel. The following surveillance were observed: 2BOS 8.1.1.2.A-1, Revision 52, "2A DG Operability", and 2 BOS 8.3.1-1, Revision SlA, "ESF Onsite Power Distribution," with no deficiencies noted. The auditor appeared knowledgeable of work responsibilitie The auditor reviewed all associated P& ids for proper logic operation and responsibilities. The auditor also verified that recorded data met requirements such as: DG cross-tie capabilities; D/G oil tank level; and proper breaker positio The inspectors reviewed trend resorts issued for the months of April, hay, and June to verify t1at corrective actions were adequately accomplished. Regulatory Assurance issues monthly trend reports based on information from various sources such as:

LERs; Deviation Reports; Information Notices; Generic Letters; and industry operating events. Daily trend meetings were held to identify trends, track items, and provide permanent closure of items. Through review and discussions with plant personnel, the inspectors concluded that trend reports were adequately prepared, with trends properly identified, and that managers initiated adequate corrective action The inspectors also assessed the effectiveness of the licensee's onsite review process that included a review of approximately 24 Onsite Review Meeting agenda items f rom the month of January 198 C__ ___._ _ _ _ .

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The inspectors verified that procedure changes, modifications,.

and proposed Technical Specification changes were approved by the onsite review group prior to implementation and in accordance with applicable procedures. The inspectors verified that reviewers possessed adequate experience, educational, and training backgrounds, and that offsite reviews were conducted when necessar The inspectors also observed an Onsite Review meeting that pertained to a new Radiation Work Permit (RWP) Program. The meeting was organized and participants concerns were adequately addresse Follow-up on Headquarters Request (2500/27, 92701)

(Closed) Temporary Instruction (TI) 2500/27: Verify or ensure licensee had tested the correct number of fasteners as required by NRC Bulletin 87-02. The TI identified that Byron Station tested 19 safety-related fasteners instead of the required 20. The inspectors reviewed the data the licensee submitted for tests performed on safety related fasteners. The inspectors ascertained that the licensee had originally sampled the correct number of safety related fasteners (20). Therefore, no action on additional samples is required by the license No violations or deviations were identifie . Engineering & Technical Support (37700)

As a result of the review of maintenance and surveillance activities the inspectors identified the following concerns: Each unit has two hydrogen monitors, Train A and Train The suction lines to containment for each train has two solenoid " fail as is" containment isolation valves in series. Appendix E of the Byron Updated Final Safety Analysis Report (UFSAR) states that separate piping penetrations of the cor.tainment were utilized by each train of the hydrogen monitoring system and each train was powered from a separate Class IE power source. The NRC Safety Evaluation Report (SER) NUREG-0876, February, 1982, accepted the design and stated that the hydrogen monitoring system meets the single failure criteria. However, during the review of maintenance activities on 1PS228A, the inspectors noted that one containment isolation valve on each suction line was powered from DC bus Ell and the other containment isolation valve from DC bur. E12. Therefore, the loss of a DC bus (Ell or E12) after a phase "A" containment isolation could result in the loss of both containment piping penetrations and therefore, a loss of both Train A and Train B of the hydrogen monitoring system.

l The licensee has been requested to provide a response on this item to NRR. The response should propose a design change to the system with a schedule for implementation or a justification for the

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existing configuration. The licensee's response is due August 30, l-l 10

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1969. This matter is considered an unresolved item pending further review by NRR.(454/88016-02; 455/88018-01(DRP)).  ;

. The maintenance work on valve 1PS230A (NWR B68316) identified !

degraded conditions of the field cable in the solenoid capsul i 1PS230A was classified as an environmentally qualified (EQ) valve where the solenoid energizes to open the valve and deenergizes to !

close. Valve 1PS230A closes on a containment phase "A" isolatio ;

The licensee re-evaluated the calculated service life for the j solenoid assembly based on energization of 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> per shift instead j of the original 15 minutes. The recalculated service life was !

utilized to determine the new qualified life. The new qualified life for the solenoid was determined as 5.0 years as compared to i the original of 14.75 years. Based on Unit 1 criticality date, the qualified life'would expire for the other hydrogen monitor discharge valve for train B, 1PS230B, in February 1990. However, since the i 1PS230A valve had indications of heat damage, the licensee will 1 inspect valve 1PS230B when a new solenoid assembly is received. The !

licensee also will revise appropriate plant procedures to identify a maximum time the 1(2)PS230B valves can remain open without notification to the EQ site organization. The preliminary new qualified life calculation performed by the station's EQ group will be reviewed by Sargent & Lundy for final incorporation into the appropriate EQ binde The inspectors also identified a concern with the test method )

identified in the EQ Binder. The solenoid operated valve tested

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to meet the EQ requirements was powered from AC with a full wave rectifier in the solenoid capsule to provide DC to the coil. The solenoid utilized for valves 1(2) P230A and B, were powered i directly from the station's DC bus, and did not have rectifier l The licensee is evaluating the affect of a direct DC source on ;

the heat rise within the solenoid capsule and any impact on EQ '

qualifications. Penoing further review by the licensee and HRC this matter is considered an Unresolved Item (454/89016-03; 455/89018-02(DRP).

The inspectors also reviewed the issue with surveillance requirements for ESF circuits associated with the Remote Shutdown Panel (0 pen items i 454/89014-01; 455/89016-01). The licensee evaluated the ESF circuits i that provided automatic start signals to the Auxiliary Feedwater (AF), !

Centrifugal Charging (CV), Component Cooling (CC), and Essential Service

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Water (SX) pumps in the event of a Safety Injection (SI) or Loss of Offsite Power (LOOP), while the equipment was being controlled f rom the RSP. The licensee's evaluation concluded that the design basis for control room evacuation did not consider a concurrent ANS Condition II, III or IV event, nor a single failure as stated in FSAR Section 7.4. Procedures 1(2) BOA-PRI-5, Control Room Inaccessibility - Unit 1 (2)"

were in place to dictate the actions necessary to i. hieve and maintain safe shutdown of a Unit if the control rcom becomes inaccessible. Also, the fire hazards safe shutdown analysis assumed that the postulated fire

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did not occur simultaneously with other accidents, events, or phenomena, with the exception of a LOOP. The analysis described the actions for a control room evacuation with and without offsite power available. Credit was taken for manual control of equipment with no automatic actuation assumed. Therefore, the SI auto-start circuits associated with the RSP were not require Even though these circuits were not required, the licensee determined that removal of the SI/ LOOP circuits from the RSP was not economically justified at this time. The circuits remained installed and although not required, will be tested to verify operability. The testing will be incorporated into the Station's surveillance program. The inspectors do not have any further concerns with this issu No violations or deviations were identifie . Security (81064)

On July 18, 1989, lightning appeared to have struck the security gatehouse that resulted in abnormalies in several security function The licensee compensated for these abnormalies expeditiously with well coordinated actions by the security forc No violations or deviations were identifie . Unresolved Items Unresolved items are matters about which more information is required in order to ascertain whether they are acceptable items, violations, or deviations. Unresolved items have been identified during the inspection and are discussed in paragraphs 6.a. and . Meetings Management Meetings (30702)

On July 27, 1989, W. D. Shafer, Chief, Reactor Projects Branch 1, and the NRC resident inspectors toured the Byron plant and on July 28, 1989, met with licensee management to discuss plant performance, plant material condition and current regulatory issues. Mr. Shafer was complimentary on the professionalism of the control room personnel during shift turnover and normal operation, Exit Interview (30703)

The inspcctors met with the licensee representatives denoted in paragraph 1 at the conclusion of the inspection on August 21, 198 The inspectors summarized the purpose and scope of the inspection and the findings. The inspectors also discussed the likely informational content of the inspection report, with regard to l documents or processes reviewed by the inspectors during the

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inspection. The licensee did not identify any such documents or processes as proprietary.

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