IR 05000334/1986015
| ML20205H431 | |
| Person / Time | |
|---|---|
| Site: | Beaver Valley |
| Issue date: | 08/06/1986 |
| From: | Lester Tripp NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION I) |
| To: | |
| Shared Package | |
| ML20205H411 | List: |
| References | |
| 50-334-86-15, NUDOCS 8608200075 | |
| Download: ML20205H431 (16) | |
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U. S. NUCLEAR REGULATORY COMMISSION
REGION I
Report No.
50-334/86-15 Docket No.
50-334 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:
June 26 - July 31, 1986 Inspectors:
W. M. Troskoski, Senior Resident Inspector A. As rs, Resident Inspector Approved by:
.M 8h b
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L. E. Trf D, Chief, Reactor Projects Section 3A
'Dite Inspection Summary:
Inspection No. 50-334/86-15 on June 26 to July 31, 1986.
Areas Inspected:
Routine inspections by the resident inspectors (138 hours0.0016 days <br />0.0383 hours <br />2.281746e-4 weeks <br />5.2509e-5 months <br />) of licensee actions on previous inspection findings, outage activities, refueling, housekeeping, fire protection, radiological controls, physical security, outage maintenance and modification activities, followup on LERs, and Design Change Pack-
' ages.
Results:
No violations were identified.
Significant items reviewed included a minor RCS boron dilution event (detail 4.a.1), an increase in the steam generator tube plugging limit (detail 5.b) and completion of the reactor trip breaker shunt coil modification (detail 5.c).
860e200075 860808 PDR ADOCK 05000
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TABLE OF CONTENTS Page q
1.
Persons Contacted....................................................
2.
Plant Status.........................................................
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3.
Followup on Outstanding Items........................................
4.
Plant Operations.....................................................
a.
Outage Activities...............................................
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b.
Re f uel i ng Outage Acti vi ti es.....................................
4 c.
Plant Security / Physical Protection.............................
d.
Radiation Controls..............................................
e.
Plant Housekeeping and Fire Protection..........................
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5.
Outage Maintenance and Modification Activities.......................
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6.
Surveillance Testing.................................................
7.
Beaver County Emergency Notification System..........................
8.
Inoffice Review of Special Reports...................................
9.
Licensee Event Reports (LERs)........................................
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10.
Review of Design Change Packages.....................................
11.
Exit Interview.......................................................
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DETAILS 1.
Persons Contacted During the report period, interviews and discussions were conducted with mem-bers of licensee management and staff as necessary to support inspection ac-tivities.
2.
Plant Status The plant remained in the fifth refueling outage during this inspection period.
Refueling activities were completed and the Mode 5 conditions achieved on July 18, 1986.
Since then, major licensee efforts have been focused on steam generator eddy-current testing and tube expansion and preparation for the Type A containment integrated leak rate test.
3.
Followup on Outstanding Items The NRC Outstanding Items (0I) 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 OIs 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:
(Closed) Violation (84-33-02): Failure to comply with SAPS for equipment con-trols, resulting in a challenge of MSSV.
The inspector reviewed the licen-see's response to this violation in a letter dated March 1, 1985.
The simu-lator group was tasked with assuring that all future simulator retraining classes incorporated administrative procedure use as a routine part of the lesson plan. The inspector reviewed the new scenarios developed prior to January 1, 1986, and observed a training class.
This item was effectively implemented.
Other commitments in regard to training included stressing ad-herence to administrative controls for onerations personnel responsible for posting caution tags at the equipment control station.
Discussions with operators indicated that this is now a routiae part of the licensee's training program.
The licensee also committed to evaluate and r.evise Operating Manual Chapter 48, Conduct of Operations, es necessary to address responsibility for placing caution tags on the benchboard and further define the circumstances requiring tagging.
This item has been completed.
Plant configuration control systems were evaluated to determine potential im-provement areas for pessible modification of the plant administrative controls.
This resulted in the development of SAP 38, Mode 5 and 6, Priority Train Logics and Technical Specifications.
During the fifth' refueling outage, the inspectors periodically verified the use of this procedure to ensure that components removed from service were not required by the priority train.
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i These items specifically addressed areas of electrical distribution, boration requirements, cooling requirements and miscellaneous technical specifications.
The inspector had no further concerns.
(0 pen) Inspector Follow Item (85-16-03): Followup on licensee's incorporation of MOV-RH-700 and 701 testing into the IST program and verification that test results are acceptable.
This item was previously updated in NRC Inspection Report 334/86-07.
The licensee performed TOP 86-14 to acquire baseline data so that test acceptance criteria could be established for a permanent sur-veillance test.
Evaluation of this test data indicated zero gpm leakage across these valves.
However, test data taken from the IIT performed by HAFA in June 1986 (see NRC Inspection Report 334/86-11) indicated that there is an apparent small leak across MOV-RH-701. This inter-system leakage was de-termined to be too small to have been identified during the earlier leak testing per TOP 86-14.
The inspector reviewed both tests and had no concerns.
A zero gpm leakage across these valves demonstrates that there is redundant pressure isolation capability between the reactor coolant system and the residual heat removal system.
Since the surveillance test has not yet been formulated, and the licensee plans to implement it prior to the next refueling
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l outage, this item remains open.
(Closed) Unresolved Item (86-04-02): Inspector review of corrective actions to prevent further reactor protection system actuations caused by failure to bypass the trip function when performing maintenance on nuclear instrumenta-tion channels.
A reactor trip had occurred in February 1986 because Opera-tions personnel failed to bypass the N-35 trip function prior to de-energizing the instrument for an equipment clearance.
To prevent another trip of this nature, the licensee has posted permanent tags on the source and intermediate range nuclear instrumentation stating that " removing the instrument fuses without bypassing the high level trip function will result in a reactor trip."
In addition, licensee retraining now includes a presentation on the Nuclear Instrumentation System response to the loss of various power supplies.
No further concerns were identified.
(Closed) Unresolved Item (85-17-02): Verify that seismic calculations consi-dered non yielding effects of metal support frame on station battery end cells.
The inspector reviewed Engineering Memorandum 72594 which addresses a poten-tial cracking problem in battery jars due to cell expansion against the sup-port racks.due to aging.
The licensee contacted the battery vendors (Exide Battery for No. 1 and 2, and C&D Battery for No. 3 and 4), and determined that the type of failure experienced at BV-1 was expected for a lead - antimony battery.
Both battery types now used in safety related systems are lead -
calcium batteries, and actual experience with long term aging shows that sig-nificant thermal expansion does not occur.
This item is closed.
(Closed) IFI (86-04-06): Followup on River Water Header to the component cooling water heat exchangers pinhole leak.
During a tour of the PAB, on July 24, 1986, the inspector verified that a patch was welded over the general area to affect repairs.
This item is close.
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(Closed) Violation (86-05-02): Failure to train QA personnel adequately against 10 CFR 71.101(b).
NRC Region I letter dated July 21, 1986, withdrew this violation.
This item is administratively closed for tracking purposes.
(Closed) Violation (86-05-04): Failure to maintain required drawings against 10 CFR 71.12.
Region 1 letter of July 21, 1986, also withdrew this violation.
It is administratively closed.
4.
Plant Operations a.
Outage Activities Inspection tours of all accessible plant areas were conducted during both day and night shifts to verify Technical Specification (TS) compliance, housekeeping and cleanliness, fire protection, radiation control, physi-cal security and plant protection, and operational and maintenance ad-ministrative controls.
The inspectors regularly verified compliance with NRC requirements and TS during operational mode changes, core alterations, and selected outage work activities.
Included in these reviews were plant radiation monitors, nuclear instrumentation systems, onsite and offsite emergency power sources, refueling water chemistry, control of boration and dilution flow paths, containment integrity and ventilation requirements, decay heat removal, and availability of necessary engineered safety features systems.
Also, various operation logs and records, including completed surveil-lance tests, equipment clearance permits in progress, status board main-tenance and temporary operating procedures were reviewed on a sampling basis.
During the course of the inspection, discussions were conducted with operators concerning knowledge of recent changes to procedures, facility configuration and plant conditions.
The inspector verified adherence to approved procedures for ongoing activities observed.
Shift turnovers were witnessed and staffing requirements confirmed.
Except where noted belcw, the inspector comments or questions resulting from these daily reviews were acceptably resolved by licensee personnel.
1.
Boron Dilution Event Technical Specification 3.9.1 requires that the RCS boron concen-tration be maintained at 2000 ppm (which includes a 50 ppm conser-
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vative allowance for uncertainty) while the reactor is in Mode 6.
The action statement requires that with less than 2000 ppm boron, all activities involving core alterations or positive reactivity changes be immediately suspended and that emergency boration at greater than 30 gpm of 7000 ppm boric acid be initiated until the concentration is restored to its limit.
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The RCS boron concentration was unintentionally diluted to about 1925 ppm on July 14, 1986.
The reactor was in Mode 6 (Refueling)
with the vessel head on but unbolted.
At the time of the event, the licensee had been spraying down the refueling cavity walls with demineralized water to prevent the spread of airborne contamination.
This water was syphoned into the vessel through the flange.
Control room personnel initially observed the reactor vessel level increase about 20 minutes into the event through a review of the two temporary level recorders; the high level alarm point had not yet been reached.
A chemistry sample was immediately taken for analysis while operators verified that all known dilution flow paths were isolated. About 30 minutes later, sample results confirmed
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that a dilution was occurring and emergency boration was initiated.
The RHR system remained in operation recirculating RCS water at 3500 gpm.
The cause of the event was subsequently determined to be water from j
a new cavity spray-down arrangement that had a higher capacity than the previous one.
Additionally, one of the drain lines was found plugged with a rag. When flow rates were lowered and the drain
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i unplugged, no further water seepage occurred.
Independent inspector calculations indicated that a maximum of 1320
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gallons was added to the RCS (estimated inventory at the time of the event was 45,766 gallons) for a 3% dilution.
Timely boration actions prevented further dilution below 1924 ppm.
The licensee complied with the LCO action statement.
Review of corrective action to preclude further occurrence is Unresolved Item (86-15-01).
2.
High Reactor Coolant System Level With the reactor in Mode 6 (Refueling) and the vessel head on but unbolted, the control room received a Reactor Coolant System High Level Alarm at about 2:30 p.m. on July 17, 1986.
After extensive investigation, the licensee determined that the source of the water
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was from the high head hot leg injection line valve (MOV-SI-869B)
which is normally closed.
Since the source of the water was from the RWST which had a boron concentration greater than 2000 ppm, the RCS concentration level remained above the technical specification limit.
MOV-SI-869B represented one of two boron injection flow path control points that are normally closed.
Upon review of plant computer data which monitors various valve positions, it was determined that after valves in the second boron addition flow path were cycled, this valve was opened at 2:10 p.m. and left open.
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Licensee interviews with control room operators on duty at the time of the event failed to determine why the valve was opened.
Either one of the operators opened the valve unintentionally or someone else entered the controlled area and opened the valve.
Either way, the reactor operator failed to maintain a positive control over this system alignment.
This aspect was immediately re-emphasized to all licensed personnel.
The inspector was informed that appropriate disciplinary actions would be taken.
b.
Refueling Activities 1.
The inspector observed portions of the fuel assembly recon-stitution work which replaced seven fuel rods with seven dummy stainless steel rods located in the outer periphery for the assembly scheduled to go in reactor core location D-13, which experienced baffle jetting problems.
Both the Onsite Safety Committee and Offsite Review Committee reviewed and approved the safety analysis of the Cycle 6 reload core design which included this fuel assembly modification work.
The DLC safety evaluation verified that the results and conclusions of the Cycle 6 RSE report remained valid.
Currently, Technical Specification 5.3.1, Design Features Section - Fuel Assemblies, is undergoing revision per DLC letter of July 18, 1986.
The inspector discussed this issue with the licensee project man-ager, NRR, and no unsatisfactory conditions were identified.
2.
Core reloading activities were conducted during the week of July 6, 1986.
Through conversations with licensee personnel and direct observations, the inspectors verified that the lic-ensee adequately maintained positive control over core reload activities, which included: ensuring constant communications between the control room, fuel handling building, and contain-ment; initially establishing and maintaining containment in-tegrity during core alterations; monitoring of refueling ac-tivities and positively accounting for locations of fuel as-semblies by the refueling SR0 during core manipulations; and constant monitoring of source range instrumentation and com-pilation of the inverse multiplication plot by test group per-sonnel.
Access to containment was positively controlled by requiring shift supervisor approval, in the form of a Security Work Permit, prior to entry. The inspector also verified that personnel were knowledgeable in the immediate response neces-sary if a cavity seal failure or fuel handling accident should occur.
3.
The licensee's administrative and procedural controls for en-suring adherence to technical specifications during re entry into Mode 6 and 5 conditions were reviewed.
In addition to OM Chapter 1.50.3, Startup Checklist A to be Completed for Cold l
Shutdown (Mode 5) Conditions, the licensee utilizes Site Ad-j
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ministrative Procedure 38, Mode 5 and 6 Priority Train Logics i
and Technical Specifications.
The SAP provides guidance for station supervisors during refueling and maintenance outages for reference in determining if a component is required'for
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the priority train operability prior to: requesting or author-izing a clearance on a specific component, The licensee.also performs OST 1.47.3, Containment Integrity Checklist for Re-fueling, to verify and maintain containment integrity during core alterations.
For this outage, several different methods were instituted to track plant status.
An Equipment Clearance Permit (ECP) in
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the Control Room is a record of all ECP's which have been
posted since the beginning of the outage.
The Control Room j
valve operating number diagrams are kept up to date with nota-tions adjacent to each valve indicating the applicable MWR or DCP, and a Plant Outage Recovery and Mode Hold Listing is being kept by the Shift Supervisors which lists all current plant
configurations which are out of normal system alignment and the applicable restrictions for each.
In addition to these
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logs, the routine jumper and lifted leads, radiation monitor setpoints, and TS action statements in effect, are being main-
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tained in their respective log books. With the exception of
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several minor problems identified by the licensee, these re-j quirements have generally been adhered to during the outage.
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c.
Plant Security / Physical Protection
J Implementation of the Physical Security Plan was observed in various j
plant areas 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; Vehicles were properly searched and vehicle access to the Protected
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Area was in accordance with approved procedures;
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Security access controls to Vital Areas were being maintained and
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that persons in Vital Areas were prcperly authorizcd.
i Security posts were adequately staffed and equipped, security per-
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sonnel were alert and knowledgeable regarding position requirements,
and that written procedures were available; and
Adequate lighting was maintained.
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The licensee reported a Physical Security Event (86-04) concerning an undetected loss of a security badge / key card, on July 23, 1986.
The badge was lost on site and went unreported for about 16 hours1.851852e-4 days <br />0.00444 hours <br />2.645503e-5 weeks <br />6.088e-6 months <br />.
The inspector discussed the specific points with the DLC Security Manager and NRC Region 1 Security Specialists.
Licensee action was determined to be appropriate.
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 the conditions of the 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 proce-dures were observed on a sampling basis.
During a backshift tour of the containment, the inspector was informed by several craft personnel of a potential contamination problem with the station's anti-contamination clothing (anti-c's).
Specifically, several pieces that had been taken from a barrel returned from an off-site laun-dry facility were found to have non-transferable contamination of up to 10,000 counts per minute (cpm).
This is in excess of limits established by Radcon Manual Chapter 3, Procedure 9.5, Anti-Contamination Clothing Monitoring, which are 600 cpm of non-transferable contamination for re-issue.
In discussions with Radcon supervisory personnel, the inspector was informed that the problem apparently occurred during receipt inspec-tion.
It is possible that items which were not acceptable for reissue were accidentally placed in the barrels with the acceptable anti-c's.
Since this problem was relatively widespread, the licensee issued a Unit Off-Normal Report and took measures to control potential rumors.
This included a meeting between the Radcon Supervisor and several Union stewards in effort to clarify the precautions taken by the station to ensure that anti-c's with greater than 600 cpm non-transferable are not reissued.
The inspector attended the meeting and discussed measures taken to prevent further occurrences with the Radcon Supervisor.
No further concerns were identified.
e.
Plant Housekeeping and Fire Protection Plant housekeeping conditions including general cleanliness conditions and control of material to prevent fire hazards were observed in various areas during plant tours.
Maintenance of fire barriers, fire barrier penetrations, and verification of posted fire watches in these areas were also observed.
1.
The licensee determined that the Honeywell Smoke Detector located in the River Water Intake Structure Pump Cubicle had been inadver-tently de-energized from May 30 to June 30, 1986.
This is contrary to the requirements of TS 3.3.3.6, Fire Detection Instrumentation,
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which requires system operability whenever equipment in that Fire l-Detection Zone is required to be operable.
However, the action
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statement requirement for a fire patrol once per hour was complied
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with by virtue of routine security patrols in the area, which the inspector has periodically observed during the inspection period.
No LC0 violation outside the action statement occurred.
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Apparently, breaker 9P8 was de-energized per Equipment Clearance.
.No. 497259 on May 30, 1986, for electrical preventive maintenance i
work. At the time the clearance was executed, both the Operating Manual and Control Room prints-were inadequate in that the Fire
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Protection System's electrical feed was not identified.
This aspect
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of the problem was previously addressed in Unit Off-Normal Report
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(UONR)'86-56, dated April 11, 1986.. Corrective action consisted
of issuing an Operating Manual' Deficiency Report instead of an
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Operating Manual Change Notice (which is effective immediately).
OMDR actions updated OM Table 38-2_on June 4, 1986, a reasonable-
time frame for this mechanism, but five days after the equipment
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l clearance was. issued.
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A second aspect that' contributed in part to this problem was a de-
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sign deficiency in the Fire Protection System-in that a loss of j
power condition was not annunciated.
This deficiency was also pre-i viously identified by the licensee and corrective actions initiated i
by developing DCP 755, Fire Protection System Monitoring, which was originated on May 16, 1986.
During a tour of the Intake Structure
on July 8,1986, the inspector noted that implementation of. the-DCP had begun.
No further concerns were identified.
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2.
During the recent months, the inspector noted an unusually high
frequency of' inoperable fire dampers.
The apparent increase is
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directly related to the performance of BVT. 1.3-1.33.5, Fire Rated
Assembly Visual Inspection, performed for all fire dampers.
Amend-ment No. 89, modified TS 4.7.15.1(b) to require that all fire dam-j pers in the safety-related areas which act as fire barriers to be t
visually inspected. In addition to the visual inspections, the lic-
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ensee agreed to mechanically trip 10% of those dampers to further verify the trip function.
This provision was added to the BVT,
which identified nine dampers that failed for a variety of reasons,
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ranging from inadequate lubrication to mechanical hangups.
In each
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instance, the licensee assured that the required fire watch was
posted.~ All of the dampers were repaired and returned to service.
j Unresolved Item (85-11 01) was most recently updated in NRC Inspec-j tion Report 334/86-07.
It was created to track licensee reinstal-lation-of the cardox blow out feature on six fire dampers in the
cable tray mezzanine area.
Since that time, the feature was re-stored; however, difficulties arose when a few of the dampers failed
the post-modification testing.
The licensee typically performs an i
OST as the post-mod test for fire dampers.
During the testing,
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F dampers of both the curtain and blade type frequently failed.
The
licensee has continuously = issued and worked MWRs but the incidence
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of failures has not declined.
The inspector brought this-concern
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to the attention of plant management.
The licensee does not have a formal preventative maintenance program for fire dampers but will
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evaluate current practices to determine what changes are necessary.
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Unresolved Item (85-11-01) will be changed to reflect this~ concern
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in addition to tracking the successful completion of OST 1.33.10.
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5.
Outage Maintenance and Modification Activities
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a.
EDG Fuel Oil Tank
While touring the plant on July 9,1986, the inspector was approached i
by craft personnel and informed of a potential problem in constructing the emergency diesel generator day fuel tank seismic support.
Specific-ally, the craft personnel were having difficulty in torquing the bolts
without snapping them. The bolts were being used in conjunction with
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crush washers.
Several failed bolts were inspected and it was noted that j
the cause of failure was apparently due to overtorquing and was not j
stress related.
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This item was brought to the attention of cognizant engineers.
Engi-neering Memorandum 90198 concluded it is advisable to use a lubricant for smooth tightening..For bolts already in place, as long as the crush washers were compressed to an average of 15 mils without failure, they are considered acceptable and capable of performing their design function.
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The inspector had no further questions.
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b.
Steam Generator Tube Plugging Due to steam generator cold leg tube thinning problems, it became appar-
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ent that the station would exceed the 1% plugging level used in the various LOCA analysis for Beaver Valley performed by Westinghouse and
presented in the FSAR.
The inspector reviewed the Beaver Valley Unit 1 DLW Return To Power Evaluation with 2.5% Tube Plugging, Westinghouse
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i letter dated July 17, 1986.
This Westinghouse evaluation concluded that based upon engineering experience,.the safety of the plant.is not im-
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pacted. Both control and protection system setpoints were reviewed and found not to need revision.
The LOCA analysis shows that the expected
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peak cladding temperature for a design based accident increased from about 2123.7* F to 2142.3* F at 2.S% tube plugging.
This remains below the 2200* F Regulatory limit.
DLC's 10 CFR 50.59. evaluation was'provided
to the NHC in a letter dated July 24, 1986.
Validation of the assump-l tions associated with this evaluation should be obtained by performance
tests with the plant operating at full power as follows:
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Precision calorimetric measurements of RCS flow and temperatures j
using the plant initial startup procedure for calorimetrics.
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Precision measurements of the steam pressure to determine the actual steam pressure at the steam generator outlet.
Review of the above test results is Unresolved Item (86-15-02).
c.
Reactor Trip Breaker Auto Shunt Trip
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During the course of this inspection period, activities associated with RTB preventive maintenance work under PMP l-1RP-BK-RTA(RTB)-1E were ob-served after breaker refurbishment by Westinghouse.
The inspector veri-fled that the work was accomplished by use of approved procedures, QC inspectors witnessed critical steps, and specified grade lubricant was applied.
After the PMP was accomplished, the inspector witnessed the RTB Auto Shunt Trip (DCP 622) post-modification test on July 27, 1986.
The test
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was properly conducted under an approved procedure and no equipment de-ficiencies were identified.
Licensee hardware changes to meet their Salem ATWS commitments are now complete.
6.
Surveillance Testing To ascertain that surveillance of safety-related systems or components is being conducted in accordance with license requirements, the inspector ob-served portions of selected tests to verify that:
a.
The surveillance test procedure conforms to technical specification re-quirements.
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Required administrative approvals and tagouts are obtained before initi-ating the test.
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Testing is being accomplished by qualified personnel in accordance with an approved test procedure.
d.
Required test instrumentation is calibrated.
e.
LCOs are met.
f.
The test data are accurate and complete.
Selected test result data was independently reviewed to verify oscuracy.
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The test provides for inuependent verification of system restoration.
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Test results meet technical specification requirements and test discre-t pancies are rectified.
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The surveillance test was completed at the required frequency.
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Portions of the following test were observed:
OST 1.11.14, Full Flow Safety Injection Pump Test, July 11, 1986.
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7.
Beaver County Emergency Notification System Through review of Control Room logs, the inspector noted that the Beaver County Emergency Notification Siren System has been inoperable frequently during this report period.
On six separate instances, since June 7, 1986, the sirens have been declared inoperable, repair crews have been dispatched
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and the NRC notified via the ENS line pursuant to 10 CFR 50.72.
The inspector l
also noted that in each instance, the siren system was repaired and declared
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operable within a few hours.
The causes of the siren inoperability in each instance were due not to equip-ment failures alone, but a combination of external causes which resulted in equipment failures.
The catalysts for these instances range from power loss in the buildings where the equipment is located to county dispatcher confusion over operation of the equipment.
The licensee has taken positive corrective action for each case to prevent further occurrence.
Discussions with Emergency Planning personnel revealed that the recent diffi-culties with the Beaver County sirens are unique to that county and will not involve Hancock and Columbiana Counties in West Virginia and Ohio, respectively.
This is because the siren system currently in use in Beaver County is a re-cently installed and more sophisticated system which has the ability, through use of a computer, to sound selected sirens rather than all the sirens in the county.
The licensee has committed to install this same system for Hancock
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and Columbiana Counties after difficulties such as those that occurred in Beaver County have been resolved.
This inspector had no further concerns, i
8.
In-Office Review of Special Reports The inspector reviewed a Special Report, dated July 9, 1986, which concerned three inoperable fire dampers which failed to close during testing.
This report is required by Technical Specification 3.7.15.a when a fire rated as-sembly or sealing device in inoperable for greater than 7 days.
The dampers were discovered inoperable on June 16, 1986, and were returned to service on July 7, 1986.
The appropriate fire watch was already in effect in the area and was continuous for the duration of the damper inoperability.
Further
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discussions concerning fire damper inoperability are contained in detail 4.e of this report.
I 9.
In-Office 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-
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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 86-05: Inoperable Filter Bank Sprinkler Nozzles.
LER 86-05 describes the identification of blockage in the Main Filter Bank fire protection sprinkler nozzles with a substance that appears to be charcoal.
On June 21, 1986, the licensee was performing BVT 1.1-1.33.1, Main Filter Bank Sprinkler Air Flow Test, when it was determined that 45 of the 90 sprinkler nozzles were clogged with a black flaky substance which appears to be charcoal.
TS 4.7.14.2.d requires that the operability of the nozzles be verified by performance of an air flow test through each open head sprinkler header and verification that each nozzle is unobstructed.
The nozzles which were blocked were declared inoperable and the applicable TS action statement was followed.
The nozzles were cleaned and returned to service on June 27, 1986.
The Chemistry Department is currently performing an analysis on a sample that was taken.
The BVT which verifies the operability of these nozzles is performed once per 36 months per TS 4.7.14.2.d, and was last performed in June, 1983.
At that time, several nozzles were also discovered plugged by what seemed to be rust or scale.
The affected nozzles were cleaned and returned to service.
The licensee is currently evaluating the cause of the nozzle blockage to de-termine what long term corrective actions are necessary.
This will be tracked as Unresolved Item (86-15-03).
LER 86-06: Misplugged Steam Generator U-Tubes.
Technical Specification 3.4.5 requires that all steam generators be operable while the plant is in Modes 1 thru 4 and that any tubes with greater than 40%
degradation be plugged.
During the eddy-current testing of the "A" steam generator (SG), the licensee discovered 'a mis plugged tube (Number R24-C62).
It was thought to have had both the hot leg and cold leg sides plugged during the last outage (Winter, 1984), but was instead plugged only on the hot leg side. The adjacent tube, R25-C62 had been mistakenly plugged on the cold leg side.
The error was determined to be caused by both the vendor technician and the licensee's inspector who mis-verified the insertion of the plug into the wrong location.
The licensee eddy-current tested both tubes involved and found that tube R25-C62 had no further degradation since last outage, and tube R24-C62 had degraded 10% more, resulting in a total 55% wall degradation.
The cold leg side of R24-C62 was plugged as was the hot leg side of tube R25-C62.
Since the tube did not fail during the cycle, the licensee has deter-mined that there were minimal safety implications due to this event.
During this outage, the licensee is using a plugging procedure which has several checks to prevent misplugging.
A calibrated, computer controlled mechanical arm first marks the tube to be plugged and a technician verifies the location.
Then the same arm inserts the plug after which two party veri-fication is required.
The use of these independent checks will decrease the likelihood of a similar event in the futur.
LER 86-07: Inoperable Fire Suppression System Smoke Detectors.
t The circumstances surrounding the inoperability of the intake structure smoke detectors are contained in detail 4.e of this report.
j LER 86-08: Information Report on Steam Generator Tube Plugging.
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During this refueling outage, the licensee performed eddy-current testing on l
100% of the tubes in all three steam generators.
A total of 31 tubes were i
found to have in excess of 40% wall degradation and were plugged.
The licen-see also noted that the majority of those tubes exhibited the phenomena of
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cold leg thinning whereby a combination of corrosion and vibration cause tube thinning in the areas of the first through sixth support plates.
In attempt to arrest the cold leg thinning, the licensee performed tube expansion of the first two support plates in 50 tubes of "A" steam generator.
This process is discussed in NRC Inspection Report 334/86-17.
10.
Review of Design Change Packages The inspector reviewed the licensee's procedures for origination and imple-mentation of design changes, including Quality Assurance Procedure OP-4, De-
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sign Change Control and Nuclear Engineering Management Procedure 2.8, Handling of Design Change Packages. The inspector verified that the necessary admini-strative controls are in place and being adequately implemented to assure that
i each design change and modification is reviewed to determine if an unreviewed
safety question exists as defined by 10 CFR 50.59.
The 50.59 reviews and DCP procedures are designed to initiate the necessary changes to TS, FSAR, plant procedures, surveillance tests, and plant as-built drawings.
Adequate proce-dures and controls are implemented during work activities and post-modifica-tion testing.
During review of QA Procedure OP-4, the inspector identified three separate
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portions of the procedure which state that design, procurement and construc-tion on a DCP may be initiated and completed up to the post-modification testing without a completed 50.59 review.
Also, in the case where NRC appro-val is required for a design change or modification which involves any unre-viewed safety questions, the DCP may be worked up to the point of post-modi-fication testing.
In practice, the licensee does not initiate work on a DCP until the 50.59 review has been completed.
However, strict adherence to this procedure would permit the initiation of construction on safety-related sys-tems without the required safety evaluation.
The inspector brought this anomaly to the attention of the licensee.
The licensee M that these anomalies existed and intends to continue the practica of completinTthe 50.59 reviews before beginning work on DCPs.
Licensee investigation into the re-visions of OP-4 revealed that these portions of the procedures were added as part of Revision 4 in March, 1977.
Currently, personnel from Operations, Engineering, Licensing and QA are evaluating the reasons for this' revision and determining if corrective actions are necessary.
This will be tracked as Unresolved Item (86-15-04).
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DCP 601, Replacement of Diesel Generator Air Start Relief Valves, replaces sixteen Kunkle relief valves on the diesel generator air start system with
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Crosby relief valves.
The Kunkle valves have a history of failing the Inser-vice Inspection Testing by not reliably retaining their set pressure.
The Kunkle valves are constructed of total brass and therefore, are not able to withstand the repeated testing which causes bending and failure of the brass trim around the valve seat.
The Crosby valves are carbon steel with stainless steel trim.
The licensee chose to replace the Kunkle valves as part of their efforts to improve diesel generator reliability.
The inspector reviewed the DCP package and identified no concerns.
The re-placement Crosby valves were tested at the Crosby facility as witnessed by licensee QC personnel.
The inspector reviewed the QC inspection report and had no further quettions.
The charging pump lube oil system modifications were made under DCP 311.
This DCP involves installation of a new seal housing design and a common lube oil cooling system for each pump and its high speed gear drive equipped with a lube oil temperature control system which varies the flow of the oil instead of the cooling water.
In effect, this DCP reduces the number of heat exchan-gers, pumps, filters, valves and instrumantation which require maintenance.
The changes were made to the 1A Charging Pump during the fourth refueling outage, Winter, 1984.
Both the 18 and 1C pumps lube oil systems were modified this outage.
The inspector reviewed the DCP package, witnessed work in pro-gress and had no concerns.
DCP training classes are given to all operators prior to station startup after outage to ensure full operator knowledge of changes made to the plant.
The inspector attended a session of these classes and verified that an adequate summary of the DCPs including their effect on plant operations was presented to the operators.
The inspector identified no deficiencies.
11.
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.
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