IR 05000272/1988017

Insp Repts 50-272/88-17 & 50-311/88-17 on 880823-0926.Major Areas Inspected:Operational Safety Verification,Maint, Surveillance,Refueling Activities,Esf Walkdown,Qa,Review of LERs & Followup on Outstanding Insp Items

ML18093B227
Person / Time
Site:	Salem
Issue date:	10/13/1988
From:	Swetland P NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION I)
To:
Shared Package
ML18093B226	List: IR 05000272/1988017 ML18093B225
References
50-272-88-17, 50-311-88-17, IEB-85-003, IEB-85-3, NUDOCS 8810210298
Download: ML18093B227 (15)

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U. S. NUCLEAR REGULATORY COMMISSION

REGION I

50-272/88-17 Report No /88-17 DPR-70 License No DPR-75 Licensee:

Public Service Electric and Gas Company P. 0. Box 236 Hancocks Bridge, New Jersey 08038 Facility Name:

Salem Nuclear Generating Station - Units 1 and 2 Inspection At:

Hancocks Bridge, New Jersey Inspection Conducted:

August 23, 1988 - September 26, 1988 Inspectors:

Approved by:

R. W. Borchardt, Senior Resident Inspector K. Halvey Gibson, Resident Inspector C. G. Miller, Reactor Engineer Section N No. 2, DRP Inspection Summary:

Inspections on August 23, 1988 - September 26, 1988 (Combined Report Numbers 50-272/88-17 and 50-311/88-17)

Aeas Inspected:

Routine inspections of plant operations including:

operational safety verification, maintenance, surveillance, refueling activities, engineered safety feature walkdown, assurance of quality, review of licensee event reports, and followup on outstanding inspection item Results:

The inspectors are continuing to assess licensee actions with regard to a Unit 1 steam generator steam flow instrumentation discrepancy which resulted in an Unusual Event declaration during the report period (paragraph 2).

Unit 2 refueling activities (paragraph 5) reviewed during the inspection period generally appear to be planned, implemented and controlled satisfactoril Increased management attention is needed with regard to housekeeping in the Unit 2 containment and the auxiliary building (both Units).

Another example of poor administrative control of documents used in the control room is discussed in paragraph 9 and indicates the need for further licensee corrective actions-in this area.

DETAILS Persons Contacted Within this report period, interviews and discussions were conducted with members of licensee management and staff as necessary to support irspection activit.

Ooera.tional Safety Verification (71707, 93702) Inspection Activities On a daily basis throughout the report period, inspections were conducted to verify that the facility was operated safely and in conformance with regulatory requirement The licensee's management control system was evaluated by direct observation of activities, tours of the facility, interviews and discussions with licensee personnel, independent verification of safety system status and limiting condition~ for operation, and review of facility record The licensee's compliance with the radiological protection and security programs was also verified on a periodic basi These inspection activities were conducted in accordance with NRC inspection procedures 71707 and 93702 and included weekend and backshift inspections. Inspection Findings and Significant Plant Events 2. Unit 1 Unit 1 began the report period operating at 100% powe On August 31, the unit tripped from full power as a result of a main turbine trip caused by a loss of turbine auto stop oil pressure during the performance of an on-line surveillance test of the low vacuum trip devic Licensee investigation of the trip did not determine the conclusive cause of the loss of the auto stop oil pressure as the condition could not be reproduced during follow up testing by the license However, during their investigation the licensee found debris in a pressure reducing orifice in the supply line to the auto stop oil syste The licensee surmised that an intermittent blockage of the pressure reducing orifice could have resulted in the reduction of the auto stop oil pressure and the turbine trip. It appeared to the inspector that while the licensee's conclusion is plausible, personnel error in performing the low vacuum trip test cannot be positively ruled out in that movement (1-2 inches) of the manual test lever will also reduce auto stop oil pressure to the turbine trip setpoin All plant systems responded as expected following the trip, and the unit was taken to cold shutdown in order to repair

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two leaking valves in the pressurizer spray line (1PS29 and lPSl).

The licensee cleaned the debris from the auto stop oil system and ran the low vacuum trip surveillance test during unit startup (turbine spinning at 1800 rpm) to verify proper operation of the auto stop oil system prior to synchronizing the generator to the gri The unit was returned to service on September 7, 198 On September 19, 1988 the licensee declared an unusual event and initiated a unit shutdown after determining that the number 12 and 14 steam generators (SG) each had both steam flow channels out of calibratio This condition requires shutdown to hot standby within 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> according to Technical Specification (T.S.) 3. Steam flow transmitter output from channels 1 and 2 of SG 12, 13 and 14 indicated as low as 95% steam flow at 100% calorimetric powe A team led by systems engineering discovered this low flow condition while taking steam flow transmitter voltages in order to troubleshoot a previously identified steam flow indication proble These voltages were taken on September 16 and analyzed on September 19, at which time they deter-mined the channels to be inoperable and in need of calibratio The calibrations were performed prior to completion of the shutdown, and the unit was returned to 100% powe Steam flow indication has been a problem for some years at Salem, and has received increased attention since the Unit 1 restart in the spring of 198 Transmitter output generally increased slowly over the period of March 1 to July 1 Control technicians decreased gain on the transmitters several times during this period, lowering indicated steam flow to match calorimetric powe This was performed using the calibration procedure lIC-series and entering calculated differential pressure (d/p)

data derived from current transmitter output voltage reading On September 16, the transmitter outputs were discovered to have shifted significantly lower (non conservative) and required increased gain adjustment The licensee has not determined what causes the transmitter output shift The systems engineering group has made several attempts in past years to find a pattern and cause for the proble They feel that the problem is caused by an actual change in steam flow nozzle d/p for a given steam flow, and not by transmitter drif As of yet no testing has been performed

by the licensee to dete~ine the effect of containment temperature changei on transmitter outpu However, the licensee has experienced environmental temperature associated drift on a similar transmitter (Rosemount*1153)

which resulted in the transmitter being replace The output of the steam flow transmitters provides signals for a steam/feed flow mismatch reactor trip and an engineered safety features main steam isolation and safety injection actuatio Steam flow indication is available at the control room console, and the T.S. require shiftly channel checks comparing steam flow channels and steam flow to feed flow mismatc Although the unit was at 100%

power while steam flow was indicating approximately 95%

and the steam to feed flow mismatch was at or near the maximum limit of 4% specified by the control room logs, the operators did not take action to determine the accuracy of the steam flow indications or declare them inoperabl The licensee could not determine how long the steam flow indications had been reading low prior to September 1 In the two days immediately following the identification of the low out of specification steam flow indication, the inspectors interviewed several operators and operations supervisory staff to determine whether there was increased watchfulness on the part of the operators regarding the steam flow instrumentatio The inspectors determined that adequate shift turnover apparently did not occur with regard to this problem, in that one control room operator interviewed was not aware that the instruments had been declared inoperable the day befor The operations supervisory staff interviewed said they would look at the steam flow indications more frequently, however the inspector was concerned that no method was put into place to ensure that excessive transmitter drift would not go unnotice Subsequently on September 22, a meeting was held with the Salem General Manager and members of the operations and engineering staff to discuss the licensee's plan of corrective action The short term corrective actions mentioned included: making a night order entry to have operators inform their supervisors when steam flow indicated 3% less than indicated power; instructing all operators on how to properly perform the steam/feed flow mismatch channel checks (which the operations engineer discovered were conducted improperly by some operators);

and briefing all operators on the importance of informing supervisory personnel when indications or equipment are

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not operating as expecte Long term corrective actions included: performing an engineering review of certain control room log parameters to verify that proper maximum and minimum setpoints are included to prevent operation outside T.S. values; performing a human performance evaluation of steam flow indication; and continuing the troubleshooting effort of the steam flow channel The licensee also committed to take as found d/p calibration data as required by the established calibration procedure The inspectors verified that increased operator awareness.was indeed focused on the steam flow instrumentation after the meetin The inspectors are continuing their assessment of this issue and are closely following licensee activities in this regar (UNR 272/88-17-01)

Unit 2 Unit 2 began the report period operating at 100% powe On August 31, 1988, the unit tripped from full power due to high No. 23 steam generator (SG) level resulting from the SG feed regulating valve (23BF19) failing ope The unit was then borated for cold shutdown and cooled to Mode 6 for its fourth refueling outag The outage was originally scheduled to commence on September 2 and is planned for 5~

days duratio Licensee investigation of the 23BF19 failure determined that the nuts on the feedback linkage to the valve positioner vibrated loose and resulted in the valve going full ope The licensee concluded that the age of the bolts and possible overtightening during previous preventive maintenance activities resulted in degradation of the threads, which contributed to the loosening of the nut Corrective actions planned by the licensee prior to Unit 2 restart include applying locktight to the threads and using overlap lockwasher These actions were accom-plished on Unit 1 prior to its return to service on September 7, 198 At the close of the report period the core off-load had been completed and numerous design changes are in progres See Section 5 for outage detail Both Units As a result of the unusually hot and dry weather conditions experienced throughout the summer months the inspectors reviewed summer service water temperature conditions as they relate to the ability to cool various safety related component Both Units have an FSAR

service water inlet temperature limit of 90 degrees No power reductions or shutdowns were required due to the extended heat spell. Technical specification relief was not sought for items related to cooling water temperatures due to the summer heat; however the licensee did perform preliminary calculations to Justify an increase in FSAR service water inlet temperatures to 92 degrees Additionally, the licensee increased monitoring of service water inlet temperatures when the circulating water inlet temperatures approached 90 degrees This included adding a strip chart recorder to monitor service water inlet temperature No major equipment degradations or failures were attributed to the high ambient temperatures in Augus Although service water inlet temperatures reached 89 degrees F during the period, no special procedures or equipment operating* configurations were required to maintain normal operations within the technical specification and design basis limit The licensee was well aware of the potential for high temperature problems if the hot, dry spell continued, and h~d contingency plans available if the FSAR limits were reached. These plans included finalizing the FSAR change to 92 degree F and notification of licensee management and NRC if 90 degree F limit was exceeded. In addition, the licensee was informed of service water problems experienced by other plants in this period by INPO contacts ~nd discus-sions with the inspector No violations were identifie.

Maintenance Observations (62703)

The inspector reviewed the following safety related maintenance activities to verify that the activities were conducted in accordance with approved procedures, technical specifications, NRC regulations, and industry codes and standard Work Order Number 880905006 Procedure Relay Test Manual

Subsection 4C2 Description 28 Diesel Generator Protective

Relays - 24 month P.M. *

Reverse Power Relay Westinghouse Type CRN-1 Subsection 9C Negative Phase Sequence Phase Time Overcurrent Relay GE Type INC-7783A

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The inspector noted that the licensee's Relay Department performs these P.M. activities. The inspector discussed with Relay technicians and supervisors the method used by the licensee to ensure that all safety related relays are maintained and tested as required. A comprehensive tracking system for relay testing does not exist, however, the inspector will continue to assess the effectiveness of the licensee's existing relay test tracking method during the next report perio.SM-0457 881001109 Various Service water pipe replacement

- 22 component cooling heat exchanger loop 2C 460V Vital Bus transformer and break.er cubicles preventative maintenance No violations were identifie.

Surveillance Observations (61726)

During this inspection period the inspector performed detailed technical procedure reviews, witnessed in-progress surveillanGe testing, and reviewed completed surveillance package The inspector verified that the surveillances were performed in accordance with *

technical specifications, licensee approved procedures, and NRC regulations. These inspection activities were conducted in accordance with NRC inspection procedure 6172 The following surveillance tests were reviewed, with portions witnessed by the inspector:

Unit 1 SP(0)4.0.5-V-CC-1 SP(0)4.0.5-V-CC-5 SP(0)4.0.5-P-CC(ll)

SP(0)4.0.S*P-CC(12)

SP(0)4.0.5-P-CC(13)

OP II-7. Unit 2 SP(0)4.8.1.1.2C7C OP IV-16. IOP-7 Inservice Inspection - Component Cooling Valves (Modes 1-4)

IST - CC Valves (Modes 5 and 6)

IST - No. 11 CC Pump IST - No. 12 CC Pump IST - No. 13 CC Pump Component Cooling System - Normal Operation 2C Diesel Generator Endurance Run and Load Rejection Test Emergency Power - Diesel Operation Cold Shutdown to Refueling

• No violations were identifie.

Unit 2 Outage Activities (60710, 37702) Refueling Activities On August 31, 1988, Unit 2 entered its fourth refueling outage scheduled for a 54 day duratio Prior to and during refueling activities the inspectors conducted inspections of in-process work, reviewed procedures and surveillance test results, and interviewed licensee and contractor personnel to verify that refueling activities were conducted as required by and approved station procedure Daily tours were conducted of plant areas including the containment to verify proper radiological controls, adherence to work procedures, and adequate general plant housekeeping condition The inspector verified the licensee 1 s completion of T.S. surveillance tests, equipment checkout, new fuel receipt and inspection, refueling crew qualification, RCS and refueling pool level controls, and establishment of loose object controls, fuel accountability, and the communication link between the control room and the refuel floo The inspectors witnessed fuel movement activities both in containment and in the control roo In addition, the inspectors followed licensee activities related to troubleshooting and repair of the fuel transfer tro~ley and observed ultrasonic testing of old fuel assemblies in the spent fue 1 poo.2 Desiqn Change Activities The following is a list of the major work activities scheduled for completion during the outage:

Steam generator hydrostatic testing (10 year ISI requirement)

Steam generator eddycurrent and tube plugging (2 of 4 generators)

Steam generator J-nozzle replacement (4 of 4 generators)

Replacement of 23 RCP motor Reactor disassembly and reassembly, and refueling activities Inservice inspections of ASME code components Replacement of 2 RCP seals Reactor thermocouple and spare CROM modifications Elimination of RTD bypass manifold piping Control room redesign for human factors Reactor protection system modifications Main turbine disassembly, inspection and reassembly Secondary piping repairs and replacements 22 CCHX service water piping replacement Replacement of 21, 22, 23, CFCU service water p1p1ng Replacement of butterfly valves/expansion joints in service water structure

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A brief description of the major design change packages being implemented during this outage is provided belo The inspector reviewed the station design change and modification program, design change packages and witnessed infield work associated with these design change EC-2151 Implementation of human factors enhancements in the control room This design change implements the significant enhancements resulting from the Detailed Control Room Design Review (DCRDR).

The enhancements include relocation of control room instrumentation, correcting abbreviations, adding demarkation between controls and instrumentation, correcting scales of instruments, labeling, and replacing indicators with an improved desig The new indicators will show a zero indication upon failure and are equipped with an LED to

, indicate power is available to the indicato These same modifications are scheduled for Unit 1 during the unit's next refueling outage (April, 1989).

During the period that the two unit's control panels are different, the licensee has stated the control room operators will normally be dedicated to one unit and they will not alternate between unit The inspector attended a meeting held by the licensee to review Work Package No. 3, which provides direction for installation and relocation of bezels associated with the residual heat removal system on the Unit 2 control board~ The work package is one of 30 to 40 work packages associated with Design Change Package (DCP) number 2EC-2151, which deals with modification of the Unit 2 control roo The meeting was held in the simulator where the control board modifications have been-completed and was attended by personnel representing all the disciplines involved in the planning, installation, and testing of the modificatio Issues such as the need to explicitly specify what test procedures would be required after relocation of a bezel and the need to install accurate labeling immediately after relocation of a bezel were discusse Based on the conduct of the meeting, discussions with licensee personnel and review of the installed changes on the simulator control boards, it appears that adequate planning has been conducted for the modificatio On September 15, 1988, the licensee's Quality Assurance Department (QA) issued a Stop Work Order (SWO) with regard to this DCP after identifying that traceability of indicating modules and interface connectors was not maintaine Traceability was reestablished, verified by QA and the SWO was lifted on September 1 * :._,,,. *,.:* *.* ~ r! *.. :. * -

2EC-2232 Bottom Mo~nted Instrumentation This design change replaces the existing movable flux monitoring system and the top mounted core exit thermocouples with an integral bottom mounted instrumentation system consisting of movable flux detectors and two thermocouples per thimble tube (one as an installed spare).

Chrome plating of the flux thimble high wear area and installation of wear reduction inserts into the guide tube holes should resolve tube wall thinning concerns. Cutting and capping of the core exit thermocouple columns should reduce the possibility of boric acid leakage on the reactor vessel head at these 5 location The inspector observed portions of the old thimble tube removal and cutup and flushing activities of the guide tube conduit through the lower reactor head and internal Also as part of this design change the licensee plans to install mechanical clamps on four spare control rod drive (crd) columns on the reactor head to reduce the possibility of boric acid leakage from thes*e locations. This use of clamps for the CRD application is under review by NRC Licensing 2-SM-0567 Steam Generator "J" Nozzle Repl~cement This DCP replaces the existing carbon steel steam generator (SG) feed ring 11J 11-nozzles with inconel "J 11-nozzles which have a carbon steel collar. The inspector observed installation and loose object control activities with respect to "J 11-nozzle replacement in the No. 21 S The inspector was informed by the licensee that an Alnor dosimeter required retrieving from the No. 24 SG second.ary and that loose o_bject controls are being more vigorously implemente **

2EC-2230 Reactor Coolant Loop Resistance Temperature Detector

. (RTD) Bypass Elimination This DCP removes RTD bypass piping including 68 valves and provides for the installation of an in-line narrow range RCS temperature measurement syste The inspector witnessed portions of the bypass piping removal and preparations for in-line thermocouple installatio EC-2187 Boron Injection Tank (BIT) Removal This DCP provides for removal of the BIT as a borated water source by cutting and capping recirculation lines between the BIT and boric acid storage tanks (BAT), disconnect associated heat tracing, and reduction of BIT boron concentration from 21,000 ppm to less than 7000 pp The inspector witnessed portions of the BIT recirculation piping removal-activitie...

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2EC-2174 ATWS Mitigation System Actuation Circuitry This design change installs a new control system called the ATWS Mitigation System Actuation Circuity (AMSAC).

Upon receiving a low steam generator water level condition the output of AMSAC starts the auxiliary feed pumps and trips the main turbin Although AMSAC is not designated as safety related equipment this modification involves work in and around safety related process cabinets and electrical separation is provided by electro mechanical relay.3 Inspection Findings No violations were identified with regard to refueling preparations and activities, however the inspector noted that the core reload 10 CFR SC.59 safety evaluation has not yet been reviewed by the Station Operating Review Committee (SORC) and that the licensee had not verified the qualifications of the NSSS vendor (Westinghouse)

refueling crew until questioned by the inspecto These items will be followed up by the inspector during the next inspection period..

On several occasions during the report period the inspectors discussed with licensee management concerns with regard to substandard housekeeping practices in the Unit 2 containment and both units*

auxiliary buildin Discrepancies identified included not well defined contaminated area boundaries, anti-contamination clothing strewn in contaminated areas and across contaminated area boundaries, and substandard control of material (i.e. scaffolding, tools, and demolition residue) in contaminated areas to prevent the spread of contamination and maintain a neat, organized work plac Within the scope of the inspectors review of the design change program, no violations were observe However, the following two areas for improvement were discussed with the licensee; (1) the maintenance training program does not appear to have a formalized process for review of DCPs to identify appropriate training needed for maintenance personnel as a result of extensive or complicated plant modifications, and (2) timeliness of revisions to plant drawings following completion of modification Positive findings identified with regard to the design change process include; (1) the new design change procedures and checklists provide prompts to ensure configuration management control and (2) supporting information provided with the packages appears to be appropriate to aid installation in the fiel No violations were identifie *..--

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12 Engineered Safety Feature (ESF) System Walkdown (71710) Inspection Activity The inspectors independently verified the operability of selected ESF systems by performing a walkdown of accessible portions of the system to confirm that system lineup procedures match plant drawings and the as-built configuratio The ESF system walkdown was also conducted to identify equipment conditions that might degrade performance, to determine that instrumentation is calibrated and functioning, and to verify that valves are properly positioned and locked as appropriat This inspection was conducted in accordance with NRC inspection procedure 7171 The Unit 1 component cooling water system was inspecte Two minor drawing discrepancies and a concern with the material condition of the reactor coolant system, steam generator, and pressurizer chemistry sample heat exchangers were discussed with system engineerin No violations were identifie.

Assurance of Quality On August 29, 1988, Salem station managem~nt effected a smooth transition with John Zupko outgoing as General Manager - Salem Operations and. Lynn Miller assuming that positio On the same date, Stanley LaBruna was assigned Vice President - Nuclear Operations responsible for both Salem and Hope Creek station In addition, John Zupko became General Manager Quality Assurance/Nuclear Safety Review and various other personnel and organizational changes were implemente Aggressive preplanning and prestaging for Unit 2 refueling outage activities were observed by the inspector The licensee compiled an Outage Information Manual and an Outage Implementation Procedure which delineate management philosophy and goals, outage organization and key personnel, and administrative protocol These documents appear to focus personnel attention on safe and efficient use of outage resources and controlled implementation of outage activitie Effective oversight of outage activities by the licensee 1s Quality Assurance Department (QA)

was evidenced by the identification by QA of a loss of material trace-ability related to control room design modifications and the issuance of a Stop Work Order until the discrepancy was resolve Gn several occasions during the report period, the inspectors discussed with licensee management a concern with regard to substandard housekeeping practices in the radio-1 ogical ly controlled areas (RCA).

Increased management attention is warranted in this area.

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The licensee's control room operations group exhibited an acceptable level of control, response, and recovery in handling reactor trips which occurred on both units within less than a one hour time frame during this report perio With regard to Unit 1 steam generator steam flow indication discrepancies, the inspector noted that this had been a long standing issue which may not have received adequate management attentio Our investigation found weaknesses in the calibration adjustment methodology, root cause deter-minations, immediate corrective action implementation, and sensitivity to the safety significance of this issu.

Review of Licensee Event Reports (90712, 92700, 90713)

Upon receipt, the inspector reviewed licensee event reports (LERs) as well as other periodic and special reports submitted by the license The reports were reviewed for accuracy and timely submissio Additional followup performed at the discretion of the inspector to verify corrective action implementation and adequacy is detailed with the applicable report summar The following reports were received and reviewed during the inspection period:

Unit 1 Monthly Operating Report - July and August 1988 Unit 2 Monthly Operating Report - July and August 1988 Unit 1 LER 88-13 Inoperable Fire Barrier Penetrations This LER discusses the inoperability of fire barrier penetration seals due to the seals not conforming to color and/or cell structure requirement The nonconformance of the seals with respect to color/cell structure is attributed to the lack of proper post-installation verification of color and cell structur Fire watches have been assigned to affected fire zones as required by Technical Specifications and procedures have been revised to require the performance of post-installation inspection of fire penetration seals for color and cell structur Replacement of the deficient seals is included as part of the licensee's ongoing Penetration Review Progra Unit 1 Special Report Supplement 88-3-1 Fire Penetration Seals Impaired for Greater Than 7 Days The Special Report Supplement identified additional degraded fire penetration seals discovered by the licensee's Penetration Seal Task Force which had not been repaired within the 7 day Technical Specification requiremen The inspector verified that fire watches have been appropriately assigned IAW Technical Specification In addition, on August 26, 1988, NRC Region I

• confirmed via-conference call with the licensee, the licensee's plans and commitments with respect to timely repair of the degraded seal *

Unit 2 Special Report 88-4 Valid Test Failure of 2A Diesel Generator On August 8, 1988, the 2A diesel generator (D/G) failed to reach the required load of 2600 KW within 60 seconds (126 seconds actual)

during a post maintenance surveillance test. Troubleshooting determined that the Woodward Governor was defective and it was subsequently re~laced. Because this was the second valid failure in the last 100 starts the test frequency was changed from 31 days to 14 days in accordan~e with Regulatory Guide 1.10 The inspector has no further question Unit 2 Special Report 88-5 Fire Penetration Seals Impaired for Greater Than 7 Days The Special Report discusses planned fire penetration seal impairments necessary for Unit 2 refueling outage activities which may not be repaired within 7 days due to engineering review that may be required to ensure installation of a proper sea The licensee has committed in the Special Report and via a conference call with NRC Region I, which took place on August 26, 1988, to keep the resident inspector informed on a real time basis of specific seals impaired and will supplement this Special Report at the end of the outage identifying those seals which have not been repaired as discussed abov Unit 2 LER 88-017 High-High S/G Turbine Trip/Reactor Trip due to a Design/Equipment problem (23BF19)

This event is discussed in Section 2.2.2 of this repor The inspectors had no further questions following review of the LE No violations were identifie.

Followup on Outstanding Inspection Items (71707)

(Open)

Partial Completion of TI 2515/73 Inspection Activities Related to IEB 85-03, "Motor-Operated Valve Common Mode Failure During Plant Transients Due to Improper Switch Settings."

The licensee's letter of May 27, 1986 contained their response to IEB 85-03, "Motor-Operated Valve Common Mode Failure During Plant Transients Due to Improper Switch Settings."

NRC review of this response led to the issuance

.of a request for additional information on April 7, 1988, and a response by the licensee on May 23, 198 NRC review

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of the additional information provided by the licensee indicates that the licensee's selection of the applicable safety-related valves, the valves' maximum differential pressures and the licensee's program to assure valve operability as requested by action item e. of the bulletin is acceptabl Further inspection is required to review the licensee's final response dated January 5, 1988 and to verify implementation of the licensee's valve operability progra (Closed)

TI 2515/98 Information of High Temperature Inside Containment/Drywell in PWR and BWR Plants The inspectors gathered containment temperature data, performed a walkdown of Unit 2 temperat~re sensor locations and concluded that the licensee's temperature monitoring arrangement appears to accurately reflect containment bulk average air temperatur Information requested by the TI was provided to NRR as reque~ted. During the inspection, the inspectors identified a discrepancy with Unit 2 tontrol room logs and Doric computer reference notebook in that these documents do not appear to accurately reflect sensor iocations and corresponding computer point This issue will be followed with a previously identified deficiency with licensee administrative control of control room document (Refer to Combined Inspection 88-14 and cover letter with 88-17 report).

1 Exit Interview (30703)

The inspectors met with Mr. L. K. Miller and other licensee personnel periodically and at the end of the inspection period to summarize the scope and findings of their inspection activitie Based on Region I review and discussions with the licensee, it was determined that this report does not contain information subject to 10 CFR 2 restrictions.