IR 05000344/1985017

Insp Rept 50-344/85-17 on 850618-0726.No Violation Noted. Major Areas Inspected:Plant Operations,Fire Protection, Physical Security,Inoperable Diesel Generators,Ler Review & ESF Verification

ML20137H315
Person / Time
Site:	Trojan File:Portland General Electric icon.png
Issue date:	08/08/1985
From:	Meyer G, Lester Tripp, Troskoski W NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION I)
To:
Shared Package
ML20137H305	List: IR 05000344/1985017 ML20137H300
References
50-334-85-17, NUDOCS 8508280249
Download: ML20137H315 (17)

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U.S. NUCLEAR REGULATORY COMMISSION DCS Nos: 841214 REGION I 850618 850718 Report N /85-17 850702 850717 Docket N Licensee: Duquesne Light Company One Oxford Center 301 Grant Street Pittsburgh, PA 15279 Facility Name: Beaver Valley Power Station, Unit 1 Location: Shippingport, Pennsylvania Dates: Jun 18 - July 26, 1985 Inspector:

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. /M[) 8 . M. Trf oski, Senior Resident Inspector Date

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& W. Mey f,' Project Engineer 8/8/Bf Date Approved by: -

, Mh 8!O6 t. E. Tri#1, Chief, Reactor Projects Section 3A ' Date Inspection Summary: Inspection No. 50-334/85-17 on June 18 - July 26, 198 Areas Inspected: Routine inspections by the resident inspector (106 hours0.00123 days <br />0.0294 hours <br />1.752645e-4 weeks <br />4.0333e-5 months <br />) of licensee actions on previous inspection findings, plant operations, housekeeping, fire protection, radiological controls, physical security, inoperable diesel gen-erators, engineered safety features verification, surveillance activities and re-lated corrective maintenance, review of selected safety issues and licensee event report Results: No violations were identified. Although no findings involving immediate safety concerns were identified, several longer term licensee followup actions are being tracked as listed in the report detail %f O

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DETAILS Persons Contacted J. J. Carey, Vice President, Nuclear Group R. J. Druga, Manager, Technical Services T. D. Jones, General Manager, Nuclear Operations W. S. Lacey, Plant Manager J. D. Sieber, General Manager. Nuclear Services N. R. Tonet, General Manager, Nuclear Engr. & Constr. Unit J. V. Vassello, Director, Nuclear Safety The inspector also contacted other licensee employees and contractors during this inspectio . The NRC Outstanding Items (01) List was reviewed with cognizant licensee per-sonnel. Items selected by the inspector were subsequently reviewed through discussions with licensee personnel, documentation reviews and field inspec-tion to determine whether licensee actions specified in the OI's had been satisfactorily completed. The overall status of previously identified in-spection findings were reviewed, and planned and completed licensee actions were discussed for those items reported below:

(0 pen) Unresolved Item (83-30-05): Determine if effluent monitoring systems are providing representative samples. During radiation safety inspection 83-30, there was a concern that the radiation monitors for the plant air ex-hausts were not collecting representative samples. The inspector noted that the wide separation between the sample nozzle location and the monitoring

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cabinets could result in losses in the interconnecting piping. This could result in (rroneously low readings for radioactive particulates and iodin The systems affected included Process Vent, Ventilation Vent and the Supple-mentary Leak Collection and Release System (SLCRS). Each is a potential re-lease path to the environment for airborne activit On December 14, 1984, the Duquesne Light Company sent the results of an evaluation of the effluent radiation monitors to the Regional Administrato The study carefully profiled the air flow in one section of the SLCRS and re-sulted in the design of a temporary isokinetic sampling probe. The licensee used guidance contained in ANSI N13.1 and ANSI N13.10 (Now ANSI N42.18-1980).

Samples of particulate and iodine activity obtained via this probe for a six menth period were compared with readings from the permanently installed moni-tors. Good correlation was obtained for the iodine activity but the particu-late activity was too low to allow meaningful comparison. An attempt to analyze particulate deposits with an electron microscope are underwa The licensee's report has been reviewed and found to provide a reasonable and technically competent approach to the resolution of NRC Unresolved Item 83-30-05. The NRC concurs that good correlation was obtained among all radiation monitors for measuring Iodine 131. The licensee's final results and conclu-

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sions regarding particulate activity monitoring will be forwarded to the Re-gional Administrator per oral commitment to the inspector. This unresolved item remains open pending review of this dat (0 pen) Unresolved Item (84-18-02): Program for analyzing repetitive equipment failures for generic application In discussions with the inspector, the Plant Performance and Test supervisor stated the scoping work continues for a formal program to review equipment failures. He stated that the current goal for establishing this program is the beginning of 1986 and that the pro-gram will apparently involve periodic retrieval of NPRDS data and periodic computer sorting of Beaver Valley equipment failure data. This item remains open pending establishment of a program to analyze repetitive equipment fail-ures for generic application (0 pen) Unresolved Item (85-06-06): Actions to reduce backlog of mechanical maintenance MWRs and Preventive Maintenance Procedures (PMPs). The inspector reviewed the June 1985 Maintenance Trend Monitoring Report, which showed that backlogged PMPs have been reduced from 20% in February to 8% in Jun How-ever, the 632 backlogged MWRs is roughly the same as that which existed in February and MWR completion rates have remained roughly equivalent. This level continues to be above the licensee's goal of 250 to 300 backlogged mechanical MWRs. The Maintenance Supervisor stated that efforts are continu-ing to reduce the backlog and that the results of these efforts would be apparent in the fal This item remains open pending licensee action to re-duce backlogged mechanical maintenance MWR (0 pen) IFI (85-12-03): Determine failure mode of component cooling water heat exchanger tub A catastrophic tube failure occurred on the 1A component cooling water heat exchanger (CCR-HX) less than one month after being returned to service following retubing. Because of the immediate need to return the heat exchanger back to service, the tube was plugged but not removed for ex-amination to determine failure mode. After completion of the retubing job on CCR-HX-1C and its return to service, the failed tube was pulled. Initial examination was inconclusive because of the wear at the break ends. Discus-sions with NECU indicated that efforts are ongoing to attempt to identify the cause of failure. This item remains open pending NECU final dispositio After the tube was pulled and plugged, several small leaks developed at the tube-tube sheet cladding interface. Several weld repairs were required before final acceptance by Quality Control. The inspector observed the final hydro of CCR-HX-1A at system pressure on July 24, 1985. The results were acceptabl (Closed) Unresolved Item (82-08-03): Review licensee action for high energy line break inaccuracies in reactor coolant system pressure instrumentation per LER: 82-10. Westinghouse had notified DLC of a potential unreviewed safety question concerning the accuracy of the RCS wide range pressure in-strumentation installed at BVPS Unit 1. The two Barton transmitters in ques-tion were on the B and C hot legs. DCP 514, Flow and Pressure D/P Transmitter Replacement, replaced the suspect transmitters with environmentally qualified

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Rosemount models during the 4th refueling outage, which was completed in January, 1985. A supplemental LER was submitted on June 24, 1985, which closes out this ite (Closed) Unresolved Item (83-21-01): Pipe support design calculations lacking analytical proof. of degree of conservatism for selection of anchor bolt stiffness. This' item is concerned with the validity of stiffness values for concrete expansion anchors as used by Stone and Webster (S&W) in the evalu-ation of safety-related pipe support base plates in response to IE Bulletin 79-02. It was identified that S&W utilizes a representative value for anchor bolt stiffness in tension equal to 250 kips / inch. Documentation of manufac-turers test data for actual bolt stiffnesses was required to substantiate the validity of the analysi Review of the licensee's response indicates that the stiffness value of 250 kips / inch was based on the secant modulus from the load deflection curve of various size anchors tested in tension. This stiffness value was estimated to be larger than 90% of the secant stiffnesses of all test samples at a load range from 10% to 30% of the ultimate bolt capacity. This load range was selected to envelope the design allowable loads for shell and wedge type anchors tested. Review of the anchor bolt stiffness summary indicates that with the exception of the Phillips self-drilling anchors tested in 4000 psi concrete at loads between 10-30% of ultimate, the average stiffness for all bolts tested was always below 250 kips / inch. It was also determined that for Hilti Kwick 1" and 1-1/4" diameter anchors, the average stiffness of all bolts tested at loads between 10-30% of ultimate, was always below 250 kips /

inch except for 1" bolts in concrete strength higher than 5500 psi. The stiffness value for those bolts were slightly higher than 250 kips / inch (264 kips / inch).

Based on the test data provided, it has been determined that the use of anchor bolt stiffness value equal to 250 kips / inch represents an upper bound of test results for various bolt sizes and concrete strength. This approach is con-sidered conservative since it overestimates the prying effect and calculated bolt loads. This item is close (Closed) Unresolved Item (83-21-02): Pipe stress calculations are lacking incorporation of pipe support stiffness. This item is related to the re-analysis of piping systems in response to IE Bulletin 79-14 without incor-porating actual support stiffnesses in the pipe stress analysis. It was identified that S&W had utilized representative support stiffnesses depending upon the size of the piping system being analyzed. A correlation between the representative stiffnesses and actual support stiffnesses was not available so that the adequacy of this approach for as-built piping configurations could be determined. Upon the staff's request, the licensee provided a tabulation of restrained direction stiffness values for several selected supports on the component cooling water and low head safety injection piping systems.

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Review of the stiffness values provided for the supperts on the low head safety injection piping indicates that the computed stiffness values are within the representative values in the piping stress analysis. The calcu-lated support stiffnesses on the component cooling piping, however, were found to be generally below those used in the pipe stress analysis. The reduction in actual support stiffnesses might result in slightly increased piping stresses and support loads as a result of the increase of signifuant piping vibration modes around the peak area of the Amplified Response Spectra (ARS).

This increase, however, will be offset by the overall conservatism in the piping analysis approach. These conservatisms are in the area of damping, peak broadening of ARS and the use of single unifctm envelop ARS vs. multiple-response spectra. These conservatisms have been nddressed by the staff in Volume II of NUREG-1061. On basis of the above, the licensee's response was found to be acceptable to close this open ite (Closed) Unresolved Item (84-15-02): Provide schedule and basis for frequency of line starter preventive maintenance. During discussions with the inspector, the Senior Electrical Maintenance Engineer statod the following concerning the hundreds of line starters installed in the plant in 14 safety-related motor control centers (MCCs) and 39 non-safety-related MCC The schedule for preventive maintenance on the line startert is every other outage (roughly 36 months) for the safety related line starters and every 48 months (during non-outage periods) for non-safety-related line starters. The basis for this frequency is the results of preventive maintenance performed on safety related line starters during the last two outages, i.e., all safety related line starters in the third refueling outage and all safety-related line starters except MCC E8 in the fourth refueling outag Based on the acceptable results (relatively low rate of observed problems), the longer frequencies of 36 months and 48 months were judged to be acceptabl Based on a cursory review of Maintenance Work Request (MWR) records over the last year, the engineer stated that the six problems experienced with the hundreds of line starters were consistent with the above preventive mainten-ance frequenc The preventive maintenance schedule for line starters is being entered into the Maintenance Planning and Scheduling Syste The inspector spot checked the Task Cross Reference Report to verify that this work is proceeding ac-ceptably. This item is close (Closed) Unresolved item (84-22-01): Evaluation of excessive setpoint drift on steam generator safety valves. On October 12, 1984, problems were experi-enced with the setpoints of steam generator safety valves, including the failure of three valves on one generator to lift at a pressure 2.5% above TS setpoint. Similar problems had occurred in 1983 and were reported on LER 83-1 The licensee conducted detailed examination and testing of one safety valve at a contractor's test facility. Tte testing was overseen by licensee and manufacturer (pressure valve) representatives. The examination revealed that

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seat and disc surfaces were in good condition and that the valve did not have any unexpected condition No definitive cause for the setpoint variation could be determine The licensee's engineering evaluation of the potential consequences of higher safety valve setpoints is documented in memo NDISEN:0020 dated December 5, 198 It concluded that the higher setpoints would not adversely affect the steam generator's operation. Specifically, the ASME Code permits a 3% toler-ance in setpoint pressure, and the steam generators have been hydrostatically tested at pressures 25% above setpoint pressure. Since the safety valves have not stuck closed, the pressure relief function of the safety valves will be me In additien, the potential effect on the reactor was evaluated, and was found to be acceptable. This item is close (Closed) Inspector Follow Item (85-06-05): Semi-annual review of the main-tenance surveillance procedure (MSP) index against the Maintenance Planning and Scheduling (MPS) Computer Program. LER 85-05 concerned the failure to perform MSP 6.67 due to its absence from the MPS. The licensee committed to perform semi-annual reviews of the MPS to ensure its accuracy. The inspector reviewed the first review, documented in licensee memo NDIDP0:0938, dated April 23, 1985. The review found three other technical specification tests which were missing from the MPS, although the testing had been performed via other means and met technical specification requirements. In addition, five non-technical specification items were found to be missing and were adde Based on the completion of this review, this item is close (Closed) Inspector Follow Item (85-06-07): Action to achieve timely reviews of completed MWR In March 1985, the inspector had noted that the mechanical maintenance group had 244 MWRs listed as Complete Awaiting Paper, i.e., the work had been performed but the administrative paperwork had not been com-pleted. *In discussions with the inspector on July 10, 1985, the Maintenance Supervisor stated that the Complete Awaiting Paper MWRs had been reduced to about 70, roughly one-fourth of the prior total, and that the level of such MWRs is now reviewed monthly during the Unit Manager's Meetin The supervi-sor stated that attempts to reduce this level of such MWRs would continue, but that a level of 70 MWRs awaiting completion of paperwork was acceptabl The inspector agreed. This item is close (Closed) Violation (85-11-02): Failure to ensure ventilation duct through fire areas CR-2, 3, 4 and CS-1 met three hour fire rating. The inspector re-viewed the licensee's response to this violation dated July 18, 1985. Initial corrective action which included posting of a fire watch per Technical Speci-fication 3.7.15 was verified in detail 5.c of NRC Inspection Report 50-334/

65-11. Permanent corrective action consisting of the installation of three hour rated fire wrapping for the duct work in question to isolate fire areas CR-2 from CS-1 and CR-4 were verified by the inspector during plant tour This modification was performed in an expeditious manner and completed on about April 12, 198 *

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The licensee noted that the apparent root cause of this violation was a breakdown in the engineering control during development of the initial design concept to upgrade various plant areas to the fire protection requirements in 1980. Since that time, the licensee has implemented administrative proce-dures to provide a method for performing the fire protection review of design change packages, identifying fire protection considerations in the design concept of the DCPs, and verification that the design output including any ECNs subsequently developed meet the Appendix R criteri These corrective actions are satisfactory and the violation is close (Closed) Unresolved Item (85-13-01): Determine whether audit requirements of Technical Specification 6.0 have been met. During an NRC inspection of the radiological environmental monitoring program, it was determined that QA had not formally audited Section 6.9.1.10 and 11 of the technical specifica-tions covering the annual environmental report requirements. Consequently, the Quality Assurance Unit conducted a line item review of the administrative controls (Section 6) to verify that the specific requirements were captured in other facility audits. By memo of July 22, 1985, those results were for-warded from the QA Manager to the Licensing and Compliance Grou Three de-ficiencies were identified by this audi (1) TS 6.9.1.10 and 11 have not been covered in past QA audit It is now scheduled to be completed under Audit BV-1-85-25 and will be part of the Teledyne field audit in the futur (2) TS 6.9.1.12 and 13 were not included in audits for 1981, 1982 and 198 These specific items were audited in 1983 and 198 The licensee has now incorporated the radiological effluent release reports as part of the standard audit scopes concerning the effluent monitoring program. (3) TS 6.10.1 re-quirements that specific quality records be retained for either five years or the lifetime of the plant were not formally verified in the past. The licensee has now scheduled these items to be reviewed during the annual clerical and record audit. The inspector has determined that these corrective actions are satisfactory and this item is close . Plant Operations General Inspection tours of the plant areas listed below were conducted during both day and night shifts with respect to Technical Specification (TS)

compliance, housekeeping and cleanliness, fire protection, radiation control, physical security and plant protection, operational and main-tenance administrative control Control Room

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Primary Auxiliary Building

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Turbine Building

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Service Building

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Main Intake Structure

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Main Steam Valve Room

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Purge Duct Room

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East / West Cable Vaults

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Emergency Diesel Generator Rooms

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Containment Building

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Penetration Areas

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Safeguards Areas

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Various Switchgear Rooms / Cable Spreading Room ,

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Protected Areas Acceptance criteria for the above areas included the following:

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BVPS FSAR

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Technical Specifications (TS)

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BVPS Operating Manual (0M), Chapter 48, Conduct of Operations

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OM 1.48.5, Section D, Jumpers and Lifted Leads

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OM 1.48.6, Clearance Procedures '

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OM 1.48.8, Records

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OM 1.48.9, Rules of Practice

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OM Chapter 55A, Periodic Checks, Operating Surveillance Tests

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BVPS Maintenance Manual (MM), Chapter 1, Conduct of Maintenance

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BVPS Radcon Manual (RCM)

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10 CFR 50.54(k), Control Room Manning Requirements

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BVPS Site / Station Administrative Procedures (SAP)

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BVPS Physical Security Plan (PSP)

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Inspector Judgement b. Operations The inspector toured the Control Room regularly to verify compliance with NRC requirements and facility technical specifications (TS). Direct ob-servations of instrumentation, recorder traces and control panels were made for items important to safety. Included in the reviews are the rod position indicators, nuclear instrumentation systems, radiation monitors, containment pressure and temperature parameters, onsite/offsite emergency power sources, availability of reactor protection systems and proper alignment of engineered safety feature systems. Where an abnormal con-dition existed (such as out-of-service equipment), adherence to appro-priate TS action statements was independently verified. Also, various operation logs and records, including completed surveillance tests, equipment clearance permits in progress, status board maintenance and temporary operating procedures were reviewed on a sampling basis for compliance with technical specifications and those administrative con-trols listed in paragraph 3 During the course of the inspection, discussions were conducted with operators concerning reasons for selected annunciators and knowledge of ,

recent changes to procedures, facility configuration and plant conditions.

! The inspector verified adherence to approved procedures for ongoing ac-

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tivities observed. Shift turnovers were witnessed and staffing require-

, ments confirme Except where noted below, inspector comments or ques-

, tions resulting from these daily reviews were acceptably resolved by l licensee personnel.

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. , NRC Inspection Report 50-334/85-16 reviewed a problem concerning a cracked cell (No. 45) on Station Battery No. 4 that was slowly leaking electrolyte. The licensee jumpered out the defective cel Initial plans were to replace both the No. 3 and No. 4 batteries

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during the next refueling outage scheduled for about May, 198 The No. 1 and No. 2 batteries were previously changed out during the fourth refueling outag The licensee has since informed the inspector that for scheduling and outage control reasons, they were now contemplating changing

each battery out, one at a time, while the plant was operating (dates to be determined). The intent is to build a qualified spare battery, test it to all of the surveillance requirements of Techni-cal Specification 3.8.2.3, then jumper out and replace the old bat-tery and reconnect the tested new battery to the original configura-tion. Discussions with Region I Management and NRR indicated that this would be acceptable provided the installed battery is equiva-lent to the original and meets all of the technical specifications and FSAR assumptions, such as seismic capability, separation, and

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capacity. 10 CFR 50.59, Changes, Tests and Experiments, allows the licensee to make changes to-the facility as described in safety analysis report without prior Commission approval provided the

! change does not involve a change in technical specification or an i unreviewed safety question. Further inspector review of the licen-see's 10 CFR 50.59 analysis will be conducted as the change concept

is firmed up by NECU. This is Inspector Follow Item (85-17-01).

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During the inspection period, the number of cracks around the end cell-metal support frame, continued to increase. The inspector noted that during a seismic event, it would appear that this in-

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terface would present the probable point of failure. This observa-tion seems to be confirmed through discussions with licensee per-i sonnel familiar with station battery equipment qualification test ! Licensee verification that station battery seismic calculations j considered the non yielding effects of the metal frame on the end

cells is Unresolved Item (85-17-02).

The atmospheric steam dump valve and code safety relief valve dis-charge rad monitor (RM-MS-100B) was declared inoperable by the lic-ensee on July 20, 1985.' With this rad monitor inoperable, Technical Specification 3.3.3.1 requires the licensee to initiate a pre-planned alternate method of monitoring the appropriate parameter

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and to prepare and submit a special report to the Commission pur-suant to specification 6.9.2 within the next 14 days following the

event. The inspector verified that the Radcon Department had been notified so that appropriate samples could be taken in the event of a release thru this pathway. Verification that the special re-port is submitted, and review of the contents is Inspector Follow Item.(85-17-03).

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10 In reviewing the BVPS Unit 1 Cycle 4 and 5 data comparing estimated critical rod position with actual for a variety of Xenon conditions, the inspector noted that criticality was consistently achieved about 300 - 600 pcm early. The greatest discrepancy is occurring during Xenon transients. Technical Specification 4.1.1.1.2 requires the overall core reactivity balance to be compared to the predicted values to demonstrate agreement within plus or minus 1% Delta K/ Though this requirement is easily met, the inspector questioned whether or not a systematic error had been introduced into either the licensee's calculational method or the vendor (Westinghouse)

supplied data. This is Inspector follow Item (85-17-04).

Currently, the licensee's procedures require the computation of an inverse multiplication plot during any startup when the reactivity is greater than 500 pcm, or fuel burnup between the last and present differs by more than 500 MWD /MTU. In discussing this with several shift supervisors, the inspector noted that most were unaware of the 500 MWD /MTU stipulatio Because of this, several earlier than expected criticalities at another facility this year, and the number of new licensed personnel and personnel in training, the inspector noted that the performance of an inverse multiplication plot during any startup might be appropriate. The Operations Supervisor ac-knowledged this concern and stated that the plots would be performed as part of the station's efforts to improve operational performance during startup . On July 8, the reactor was shut down due to main condenser tube leaks. While operating at full power with one of the two heater drain pumps unavailable for use, the remaining heater drain pump experienced problem Power was reduced, and the heater drain tank overfow was routed into the main condenser (the heater drain pumps normally pump this water into the feedwater line). Shortly there-after, reduced condenser vacuum and greatly increased secondary water conductivity indicated condenser tube leaks. At 2047, a shutdown was initiated, and the turbine was manually tripped at 223 Soon a steam dump valve incorrectly opened causing decreasing levels in the steam generators. At 2237, the reactor tripped due to low level in steam generator "A". Also during the shutdown, pressurizer pressure control was somewhat errati The main condenser tube leaks were repaired by plugging. Five tubes had sections cumpletely missing, and nine tubes had leaks. Ap-proximately 30 adjacent tubes were plugged as a preventive measur One heater drain pump was repaired. Failed components were replaced in the steam dump valve controller and the pressurizer pressure controlle Following the above repairs, the reactor was restarted with criti-cality occurring at 1333 on July 8. The generator was on line at 1606 and full power was reached eight hours later. The inspector observed the startup process from the control room.

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The inspector reviewed Draft Incident Report 85-104 dated July 7, which reviewed the unplanned shutdown and the associated equipment problem The inspector had no questions on the revie Plant Security / Physical Protection Implementation of the Physical Security Plan was observed in the areas listed in paragraph 3a above with regard to the following:

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Protected area barriers were not degraded;

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Isolation zones were clear;

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Persons and packages were checked prior to allowing entry into the Protected Area;

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Vehicles were properly searched and vehicle access to the Protected Area was in accordance with approved procedures;

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Security access controls to Vital Areas were being maintained and that persons in Vital Areas were. properly authorized;

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Security posts were adequately staffed, equipped, and security per-sonnel were alert and knowledgeable regarding position requirements, and that written procedures were available; and

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Adequate lighting was maintaine No discrepancies were observe d. Radiation Controls Radiation controls, including posting of radiation areas, the conditions of step-off pads, disposal of protective clothing, completion of Radi-ation Work Permits, compliance with Radiation Work Permits, personnel monitoring devices being worn, cleanliness of work areas, radiation control job coverage, area monitor operability (portable and permanent),

area monitor calibration and personnel frisking procedures were observed on a sampling basi No discrepancies were observed, e. Plant Housekeeping and Fire Protection

Plant housekeeping conditions including general cleanliness conditions and control of material to prevent fire hazards were observed in areas j listed in paragraph 3a. Maintenance of fire barriers, fire barrier i

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penetrations, and verification of posted fire watches in these areas was also observed. The inspector noted that continued housekeeping efforts on the entire plant are showing good improvement . Inoperable Diesel Generator Discovery At about 1:00 a.m. on July 17, 1985, during performance of the monthly sur-veillance test (OST 1.36.1), the No. I diesel generator only accepted a 390 kw load. Licensee investigation determined that the load limiter was mispo-sitioned at about one-third its normal settin After consultation with plant management, the load limiter was adjusted to full load (2850 kw) and the surveillance test successfully complete Immediate Action Immediate implications were that the No. I diesel generator would not have been able to accomplish its design function until an operator could be di-spatched to identify and correct the problem. The licensee initially believed that the mispositioned setting could be attributed to either motor vibration, inadvertent movement during housekeeping efforts several days before, or de-liberate tampering. The second diesel generator was immediately checke A walkdown of other plant equipment identified no other abnormalitie Based on the lack of evidence that deliberate tampering with plant safety equipment occurred, the licensee reported the event to the NRC via the ENS two hours after discovery as an inoperable safety system. The rules and regulations do not require the licensee to identify suspected tampering events as such. Due to the NRC's sensitivity to these events, the inspector re-quested the licensee to notify the NRC in the future of any such events so that appropriate actions could be immediately implemented by the Region. The comment was acknowledged by the plant manager. In followup discussions, the inspector noted that should a similar event occur, it would be prudent for the licensee, at this time, to develop a list of critical equipment in standby systems that are not normally operated such that the shift supervisor could conduct a very quick check to assure that important plant systems have not been tampered with. This list should not be widely distributed. Those com-ments were also acknowledged by the plant manage Description of Operation Automatic fuel control to the General Motors EMD Series 999-20, diesel gener-ators is provided by Woodard UG8 dial type governors. This model governor is hydraulically operated with a differential type servomotor for isochronous

, operation; that is, a constant engine speed of 900 RPMs is maintained over j the 0-2850 kw load range. Standard controls include speed adjustment, speed droop and a load limiter. There are two booster pumps which immediately start

on any demand signal to avoid waiting for the governor to build up hydraulic

) pressure, thus allowing a " fast start."

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The load limit device operates hydraulically and has a load indicating pointer position which can only be changed by turning the load limit knob when the governor is running or when there is oil pressure in the accumulator. Both the control knob and load indicating pointer (located underneath the control knob) have position reference arrows. At BV-1, the load limiter is required to be set at 10, which is equivalent to the 100% load of 2850 kw. The load indicating pointer, however, varies its position according to the actual position of the fuel racks. When the diesel is running, this is an accurate indication of load. However, when the diesel is shutdown, the hydraulic pres-sure is bled off the governor, the final position of the fuel racks and hence the load indicating pointer at some time after the racks were in the no fuel oil position, is determined by how fast the pressure was bled down and the amount of friction in the rack linkage. Licensee discussions with the vendor indicates that this is a random condition that does not impact the ability of the diesel to " fast start" because of the two booster pump The two diesels are normally operated once per month for at least one hour, fully loaded, per manufacturer's recommendations, for routine surveillance testing (OSTs 1.36.1, 2). The lube oil is heated to about 145 F, and the diesels are slow started from the control room by running the governor control switch down to the Low Stop position. The engine is then idled for several minutes prior to increasing speed to its rated 900 RPM. An auxiliary operator records various parameters and checks for proper operation. The A0 is not directed by the OSTs to change any of the governor controls locall After a one hour run, the diesels are shutdown from the control room by simultaneously depressing two stop buttons (wired in series). This activates a timer iri the control circuit set for 11.5 minutes and sets the fuel racks to its low position to allow the engine to cool down to an equalibrium tem-perature at idle speed. After the timer runs out, the engine shuts down when the governor closes the fuel rack The governor's two booster pumps stop, ard hydraulic pressure drops. Electrically, the DC control Raise circuit drives the speed setting of the governor to its operating point, where the high limit switch operates to open the circui The synchronizing motor then coasts to a stop against a pre positioned mechanical stop (940-945 RPM). The diesel is now ready for a " fast start."

Review of Followup Actions The inspector observed licensee attempts to identify a mechanism by which one action could turn the No. 1 load limiter. The first try failed because the fuel racks were positioned all the way in. Two actions were required to move the limiter; pull the fuel rack lever out, then simultaneously adjust the limiter. This seemed to preclude inadvertent operatio After the licensee contacted the diesel vendor,.the inspector accompanied an SR0 to the diesel generator rooms. At that time, the No. 2 diesel fuel lever was found all the way out. This condition was the "as-left" condition after it was last run. The load limiter could easily be moved until it matched the

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load indicating pointer, at which position further movement was mechanically blocke According to the vendor, this is an expected condition, as discussed in the description of operatio r The licensee informed the inspector that: Subsequent testing and system walkdowns identified no abnormal condition . Review of diesel generator room access records identified over 200 people who were in the diesel generator rooms since the last monthly test of the No. 1 engine. Questionnaires and interviews determined that a total of 36 man-hours had been spent cleaning the diesels several days before the even . Although a tampering act cannot be positively ruled out, it is believed that the load limiter was probably mispositioned during cleaning. If an individual realized that it was inadvertently moved, a quick look at the load indicating pointer under the knob gives a ready reference with which to realign the knob arrows. From a human factors point of view, this second mistake is possibl Previous to this event, auxiliary operators toured the diesel rooms once per shif The logs did not require them to check the load limiter's settin The inspector verified that these logs have now been revised to require tha . Engineered Safety Features (ESF) Verification The operability of the Emergency Diesel Generators were verified on July 19 and 22-23 1985, by performing a walkdown of accessible portions that included the following as appropriate:

(1) System lineup procedures match plant drawings and the as-built configura-tio (2) Equipment conditions were observed for items which might degrade perfor-manc Hangers and supports are operabl (3) The interior of breakers, electrical and instrumentation cabinets were inspected for debris, loose material, jumpers, et (4) Instrumentation was properly valved in and functioning; and had current calibration date (5) Valves were verified to be in the proper position with power availabl Valve locking mechanisms were checked, where require This walkdown was in response to a mispositioned governor limit setting iden-tified by DLC during performance of the monthly surveillance test. No other deficiencies were identified by the inspecto r .

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i 6. Surveillance Activities During observations of OST 1.46.5, Hydrogen Post Accident Purge System Test, conducted on June 21, 1985, the mass flow meter (FIT-1HY-101) failed to re-spond. Technical Specification 4.6.4.3 requires the hydrogen purge system to be demonstrated operable at least once per 31 days by verifying that the purge fan operates for at least 15 minute This was demonstrated by measur-ing the differential pressure across the filter bank for flow verificatio An MWR was issued to correct the out-of-service flow meter's power suppl Licensee action was acceptabl OST 1.33.22, Halon Storage Cylinder Operability Test for Cable Tunnel and Process Equipment Areas, was initiated on July 25, 1985. This surveillance test is to verify that the halon storage cylinder weight is within 95% of the full charge weight by either (1) actually weighing the cylinders or (2) meas-uring liquid halon level in the cylinde The licensee attempted to perform this surveillance by using a transducer probe to determine the liquid leve The probe exhibited erratic behavior and was declared unreliable. Further discussions with icensee personnel indicated that DLC intends to perform this semi-annual test t,y using the more cumbersome cylinder weight method. The inspector verified that either method was acceptable per Technical Specifica-tion 4.7.14.5. Because the test was not signed off as complete and remains scheduled at this time, the inspector had no further concern OST 1.24.4, Steam Turbine Driven Auxiliary Feed Pump Test, was observed on July 10, 1985, without even . Review of Selected Safety Issues Anchor / Darling Valve Company issued a 10 CFR 21 report to the NRC dated June 11, 1985. It detailed a problem with tilting disc check valves with tack welded bushings. The tack welds which lock the hinge pin bushings in place were found cracked at another nuclear facility. Beaver Valley Unit 1. was identified as having been supplied with similar safety re-lated check valves. Review of DLCs resolution is Inspector Follow Item (85-17-05). A potentially generic problem was identifed at.Surry and North Anna (3-loop Westinghouse NSSS plants) concerning a possible unanalyzed condition in the recirculation spray heat exchangers (RSHX) located inside con-tainment. Under early LOCA conditions when containment is pressurized but the tube side of the RSHXs has not yet been, the RSHX diaphrams could fai Since the same type of RSHXs appear to be used at Beaver Valley, Units 1 and 2, the inspector contacted NECU to determine the planned resolution. This is Inspector Follow Item (85-17-06).  ! The inspector was informed by the licensee of a problem concerning 5KV motor cable splice insulation, discovered at Unit 2 and applicable to Unit 1. Apparently, the river water and component cooling water pump cable splices received only 4-1/2 wraps of insulation as opposed to the

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17 wraps recommended by the vendo Stone & Webster Engineering Company, the architect-engineer, discovered this during a review of Unit 2 wor The licensee determined that other Unit 1 SKV motors were not subject to this concern because DCP 351, Equipment Qualification, upgraded or qualified all Category 1 cabling splices located inside containmen The licensee informed the inspector that an independent engineering re-view confirmed that the 4-1/2 wraps of insulation would be sufficient for continued operation. They did however, recommend that it be upgraded to the vendor recommended 17 wraps when practical. The inspector noted that both the river water and component cooling water systems have a third " swing pump" that could be taken out of service for repair without impacting the operability or redundancy of the associated system Licensee corrective action on this item is Inspector Follow Item (85-17-07). Through discussions with I&E Headquarters personnel, it was determined that the DLC responses to IE Bulletin 82-02, Degradation of Threaded Fasteners in the Reactor Coolant Pressure Boundary of PWR Plants, dated August 2, 1982 and December 8, 1983, did not provide all of the requested information. Specifically, action item 3.b of the bulletin requested identification of closures and connections where fastener lubricants and injection sealant materials have been or are being used. A description of the types and compositions of materials was also requested. The bases for this request is that a high leak rate has been experienced where certain lubricants were used; molybdenum disulfite (moly) and alcohol /

graphite compositions. Per I&E personnel, investigations of several brands of moly showed that the friction factor varied by a factor of 1 This can apparently lead to inadequate tensioning and result in slight leak Experience indicates that 80% of the leaks will result in ac-celerated corrosion. It is therefore important to use lubricants and sealants of known chemical composition in applications on the primary syste , The inspector informed the licensee that a supplemental response to Bul-letin 82-02 addressing the above concerns is required. This is Unre-solved Item (85-17-09).

Previous review of threaded fastener inspection results and inspection program modifications is documented in Inspection Report 50-334/83-08 and 85-0 . Review of Licensee Event Reports (LERs)

The inspector reviewed LERs submitted to the NRC:RI office to verify that the details of the event were clearly reported, including the accuracy of the description of cause and adequacy of corrective action. The inspector deter-l

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mined whether further information was required from the licensee, whether generic implications were indicated, and whether the event warranted onsite followup. The following LERs were reviewed:

LER: 85-11 - Inoperable Chemical Addition Pump This item was initially reviewed by the inspector as documented in detail 6 of NRC Inspection Report 334/85-1 Long term corrective actions mentioned in the LER include a proposed change to procedures for racking in the 480 volt breakers and line starters to now require that their associated component is cycled to ensure proper makeup of all three phases. This functional test is currently captured in Special Operating Order 85-4, 4KV Breakers, 480 Volt Breakers and Line Starters. The operating order contains a logic diagram that would require shif t personnel to contact the Operations Supervisor should it be determined that any piece of equipment cannot be so cycled, for whatever reason. Although this provides the immediate mechanics for preventing the problem from recurring,it does not take the place of a permanent procedur Verification that such a procedure is permanently incorporated into operations administrative controls is Inspector Follow Item (85-17-08).

LER: 85-12 - Surveillance Program Deficiencies Technical Specification Limiting Condition for Operation 3.5.3, requires a minimum of 1 ECCS subsystem to be operable when in Mode Technical Speci-fication surveillance requirement 4.5.3, requires the subsystem to be demon-strated operable per the applicable surveillance section of TS 4.5.2. This technical specification, in turn, requires each ECCS subsystem to be demon-strated operable at least once per 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> by verifying that specified ECCS valves are in the indicated position with power to the valve operator control circuits disconnected by removal of the plug in the lockout circuit from each circuit. TS 4.5.2 is required when the plant is in Modes 1 thru 3. During a review of TS requirements, the licensee determined that a deficiency existed in the surveillance verification logs. Specifically, Log L5-A performed the required surveillance of TS 4.5.2 for Modes 1 thru 3 only. No log was con-ducted when the plant was in Mode 4. However, Station Startup Procedures, contained in OM Chapter 1.50.4 do provide for a double verification of the valve's correct alignment prior to exceeding 200 F. To correct this deft-ciency, the valve check was put in surveillance verification Log LS-11, which is performed in Modes 1 thru 4. The inspector verified that the licensee's action in this area is complet . Exit Interview Meetings were held with senior facility management periodically during the course of this inspection to discuss the inspection scope and findings. A summary of inspection findings was further discussed with the licensee at the conclusion of the report period.