IR 05000334/1986007
| ML20198S676 | |
| Person / Time | |
|---|---|
| Site: | Beaver Valley |
| Issue date: | 05/29/1986 |
| From: | Lester Tripp NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION I) |
| To: | |
| Shared Package | |
| ML20198S668 | List: |
| References | |
| TASK-2.F.1, TASK-TM 50-334-86-07, 50-334-86-7, IEB-84-03, IEB-84-3, NUDOCS 8606100516 | |
| Download: ML20198S676 (18) | |
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U.S. NUCLEAR REGULATORY COMMISSION
REGION I
Report No.
50-334/86-07 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:
April 19 - May 21, 1986 Inspectors:
W. M. Troskoski, Senior Resident Inspector A. A. Asars, Resident Inspector (Trainee)
L. J. Prividy, Resident Inspector H
F. Va Kessel, Reactor Engineer Approved by:
$. i Lald
U.. E. Trfpp, Chief, Reactor Projects Section 3A dhte Inspection Summary:
Inspection No. 50-334/86-07 on April 19 - May 21, 1986.
Areas Inspected:
Routine inspections by the resident inspectors (116 hours0.00134 days <br />0.0322 hours <br />1.917989e-4 weeks <br />4.4138e-5 months <br />) of licensee actions on previous inspection findings, plant operations, outage activi-ties, housekeeping, fire protection, radiological controls, physical security, engineered safety features verification, surveillance testing, reactor cavity seal, followup on special reports and LERs, and fuel assembly design specifications.
Results:
No violations were identified.
A concern about timely completion of maintenance work on fire protection equipment is discussed in Detail 4.f.
8606100516 860530 DR ADOCK 0500
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TABLE OF CONTENTS
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1.
Persons Contacted....................................................
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2.
Plant Status.........................................................
3.
Followup on Outstanding Items...................
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4.
Plant Operations.....................................................
General.........................................................
a.
b.
Operations......................................................
Plant Shutdown /0utage Activities................................
c.
d.
Plant Security / Physical Protection.................
Radiation Controls.................................
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e.
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f.
Plant Housekeeping and Fire Protection..........................
5.
Review of Reactor Cavity Seal (IE BU 84-03)..........................
6.
Engineered Safety Features (ESF) Verification........................
t I-7.
Surveillance Testing.................................................
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In-Office Review of Special Reports..................................
9.
In-Office Review of Licensee Event Reports...........................
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10.
Fuel Assembly Design Specifications..................................
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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 staf f as necessary to support inspection activi ty.
2.
Plant Status The plant operated at full power until April 23, 1986, at which point the end of core life power coast down began.
It was manually shutdown on May 17, 1986, to start the fifth refueling outage, scheduled for about 92 days.
Cold shutdown conditions were achieved on May 18, 1986.
3.
Followup On Outstanding Items 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 OIs had been satisfactorily completed.
The overall status of previously identified in-spection findings were reviewed, and planned and completed licensee actions
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were discussed for those items reported below:
(Closed) IFI (85-19-05): Provide habitability survey requirements for each emergency facility during its actuation and occupation.
The licensee updated EPP-IP 1.5, Emergency Support Centers Actuation, Operation and Deactivation, to include provision for habitability surveys of these facilities and actions to be taken if survey results are unacceptable.
The inspector had no further Concerns.
(0 pen) Unresolved Item (85-11-01): Modification and successful testing of ventilation dampers VS-D-85B and VS-D-908.
This item is discussed in detail 4f of this report.
(Closed) IFI (85-22-05): Review the results of licensee evaluation of the fire damper program to ensure all required dampers are installed.
This item was initiated by the discovery of two missing fire dampers in the ventilation ducts between the Relay Room and the Process Control Room.
These dampers have been installed and successfully tested.
The licensee performed a re evalu-l ation of all safety-related plant areas including a walk down of the areas, and an evaluation of ventilation ductwork penetrating fire area boundaries.
The evaluation concluded that there are no compromises to any plant fire area barrier.
After reviewing the evaluation, the inspector had no further con-cerns.
(Closed) IFI (85-18-07): Investigate No. 2 emergency diesel generator governor problems.
During a monthly surveillance test, the Woodward governor momen-tarily failed to limit idle speed to 490 rpm.
A maximum speed of 700 rpm was
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observed prior to dropping down without any apparent reason.
To determine the cause of this control problem, the licensee sent the governor to the ven-dor for inspection, repair and testing.
The inspector reviewed Woodward Governor Company repair report dated October 23, 1985.
The receipt test failed to identify any reason for the spurious behavior.
The governor was reworked, satisfactorily retested a second time, and returned to the licensee for use as a qualified spare.
The inspector had no further concerns and this item is closed.
(Closed) IFI (82-24-01): Followup on II.F.1.4, Containment Pressure Monitor; Technical Specification change and correct audit discrepancies.
Since this item was last reviewed in Inspection Report 334/85-06, TS Change 94, Rev. 1, was submitted on February 3, 1986, and is currently under review by Region 1 staff.
The second part of this item concerned upgrading the wide range containment pressure transmitter to IEEE 323-1974 standards.
Through discus-sions with licensee personnel, the inspector was informed that Engineering Memo 30471 dated June 19, 1985, reviewed this item and determined that the containment pressure monitors installed under DCP 297 were qualified to the 1971 Standard.
This is allowed by NUREG 0588 due to the fact that the license for Deaver Valley Unit 1 was issued prior to May 23, 1980, and that the moni-tors in question were already purchased and qualified for a service life of ten years.
The inspector had no further questions and this item is closed.
(0 pen) Inspector Follow Item (85-16-03): Followup on licensee's incorporation of M0V-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 334/85-27.
On May 17, 1986, the licensee performed TOP 86-14, Leak Test of MOV-RH-700 and 701.
This test provided a method of leak testing the RHR inlet MOVs through use of the RHR sample valves at the Reactor Plant Sample Panel.
The test was done one time only for data acquisition in order to develop acceptance criteria for a permanent OST.
The licensee will then submit a letter to Region 1 which will include copies of the TOP results, the test acceptance criteria derived from the TOP performance, and the permanent OST which will be performed each outage, beginning with the Sixth Refueling.
The inspectors made a detailed review of the TOP system configuration and results and had no concerns.
This item will remain open pending licensee evaluation of the results of the TOP and incorporation of the new OST into the IST program.
(0 pen) Violation (85-02-01): Failure to properly perform leak testing of RCS pressure isolation valves per ASME Subsection IWV-3420, and failure to pro-perly perform SI accumulator check valve leak test.
This item is discussed in detail 7 of this inspection report.
(Closed) Violation (84-15-01): Inadequate test controls for station batteries.
The licensee provided their response to this violation in a letter dated July 17, 1984.
An updated design duty cycle for each safety related station bat-tery was developed and incorporated into BVT 1.1-1.39.1-4, Battery and Charger Load Test.
These surveillance tests were reviewed for technical adequacy in
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NRC Inspection Report 334/84-30 and found acceptable.
The inspector also reviewed the last battery service tests that were completed in December, 1985, and found the results acceptable.
This item is closed.
The following items all concern Emergency Diesel Generator (EDG) reliability and will be administratively closed and consolidated intounresolved item (86-07-01) to track the licensee's efforts in improving EDG reliability.
(Closed) Unresolved Item (85-22-06): Followup of licensee resolution of more than 60 discrepancies that exist between the implemented PM program and the vendor recommended actions.
(Closed) IFI (85-18-05): Followup licensee determination of whether routine PM recommendations referenced in the vendor manual will be added to the PM program.
(Closed) IFI (85-18-06): Review of licensee evaluation of the entire air start subsystem problems which include moisture buildup, excessive air compressor maintenance, and relief and discharge check valve failures.
(Closed) IFI (84-22-02): Licensee investigation into the cause of the high failure rate of No. 1 EDG Manual Start Relay and followup of appropriate cor-rective action.
4.
Plant Operations a.
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, and operational and maintenance administrative controls.
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
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Acceptance criteria for the above areas included the following:
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Technical Specifications (TS)
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BVPS Operating Manual (OM), Chapter 48, Conduct of Operations OM 1.48.5, Section D, Jumpers and Lifted Leads
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OM 1.48.6, Clearance Procedures OM 1.48.8, Records
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OM 1.48.9, Rules of Practice
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OM Chapter SSA, Periodic Checks, Operating Surveillance Tests BVPS Maintenance Manual (MM), Chapter 1, Conduct of Maintenance
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10CFR50.54(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 eviews were 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 condition existed (such as out-of-service equipment), adherence to ap-propriate 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 4a.
During the course of the inspection, discussions were conducted with operators cencerning 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-tivities observed.
Shift turnovers were witnessed and staffing require-ments corfirmed.
Except where noted below, inspector comments or ques-tions resulting from these daily reviews were acceptably resolved by licensee personnel.
(1) On May 9, 1986, at 9:38 a.m., with the plant at approximately 85%
power, vital bus No. I was lost for a period of seven minutes.
Technicians were performing routine maintenance on rad monitor RM-RW-1000 when a connector slipped and accidentally connected with another terminal on the back of the rad monitor rack.
The rack power supply breaker opened and vital bus No. 1 inverter was los.
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The loss of vital bus No. 1 activated many control room annunciators but did not cause a plant trip.
All systems functioned as required.
Operators immediately placed all three main feedwater regulating valves in manual control and stabilized steam generator levels.
Within seven minutes, vital bus No. I was restored with the auxil-iary power source per Abnormal Operating Procedure (A0P) 29, Loss of Vital Bus No. 1.
The inspector observed plant recovery per A0P 30, Extended Loss of Vital Bus No. 1.
The plant was returned to normal operating conditions by 11:00 a.m. and Vital Bus No. 1 in-verter was placed back in service at 12:06 p.m.
In order to prevent future occurrences such as this, the licensee is planning to change the procedure for maintenance on rad monitors to require that the power pins be pulled before work commences.
This appears acceptable and the inspector had no further questions.
(2) While in the process of venting the charging pump suction header on May 11, 1986, a High-High radiation alarm was received which resulted in the redirection of air flow through the supplementary leak collection and release system (SLCRS) for discharge at the elevated release point.
All systems functioned as designed.
Operations personnel had installed a vent rig per 0M Chapter 7.A.N, Returning a Charging Pump to Service, and Valve CH-312 was opened to initiate the venting.
One High-High rad alarm and several high rad alarms were received in the control room shortly after. CH-312 was immediately closed, and within a short period, all rad monitors indications returned to normal.
The affected rad monitors were located on elevation 768' of the Primary Auxiliary Building (PAB).
The High-High alarm was received for about one minute on RM-VS-102B with the corresponding strip chart recording of 5000 cpm.
SLCRS operated for about 10 minutes; it is designed to initiate upon re-ceipt of a Hi&9@ rad alarm from either one of the PAB exhaust
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system rad monitors (RM-VS-102A and RM-VS-1028).
Discussions with rad con personnel indicated that the amounts re-leased had a negligible effect on the yearly permissible dose rates to the unrestricted areas due to radioactive gaseous effluents as described in Technical Specification 3.11.2.1.
The inspector had no further conceins.
c.
Plant Shutdown / Outage' Activities (1) The inspectors conducted several backshift tours to observe opera-tions activities for bringing the plant to cold shutdown conditions during the weekend of May 16 - 18, 1986.
Technical Specification requirements related to minimum shutdown margin, and power distri-bution limits were independently verified.
During RCS cool down, technical specification pressure / temperature limits for the reactor coolant system and pressurizer and initiation of the overpressure protection system was also verifie.
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With the plant in Mode 3 (Hot Standby) operators installed the power fuses for the two source range monitors (SRM) and energized the instruments on May 17, 1986.
Almost immediately, SRM NI-32 failed high, causing the reactor trip breakers to open. The inspectors observed the operator's response to the spurious condition and identified no concerns.
The cause of the SRM trip was subsequently determined to be due to a failed detector.
After changeout, both SRMs were successfully recalibrated.
The inspectors noted that during the shutdown evolution, the shift technical advisors performed an independent review of various tech-nical specification requirements for the station that are impacted by this evolution.
This independent review that is done apart from the Operations Department is considered a good practice.
(2) With the reactor in cold shutdown, an inadvertent safety injection signal was initiated for Train B on May 20, 1986, during an elec-trical inspection under the main control room panel.
The cause of the event was due to a 1cose wire on the Train B low steam pressure SI block switch that made up the reset contact.
This allowed the actual low pressure signals logic to complete its path to the solid state protection system.
The only equipment that actuated were valves responding to the containment isolation Phase A signal and startup of the 1C standby river water pump.
All other equipment was de-energized in this mode.
The licensee initiated a Maintenance Work Request to investigate and repair the defective switch. ENS notifications were made for this event.
The inspectors had no further concern on this item.
d.
Plant Security / Physical Protection Implementation of the Physical Security Plan was observed in the areas listed in paragraph 4a above with regard to the following:
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
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Protected Area; Vehicles were properly searched and vehicle access to the Protected
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Area was in accordance with approved procedures; Security access controls to Vital Areas were being maintained and
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that persons in Vital Areas were properly authorized; 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
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Adequate lighting was maintained.
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No discrepancies were observed.
e.
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.
No deficiencies were observed.
f.
Plant Housekeeping and Fire Protection
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Plant housekeeping conditions including general clehnliness conditions and control of material to prevent fire hazards were observed in areas listed in paragraph 4a.
Maintenance of fire barriers, fire barrier penetrations, and verification of posted fire watches in these areas were also observed.
NRC Inspection Report 334/85-11, detail 5.a, discussed issues involving six dampers which penetrate the Cable Tray Mezzanine floor.
At that time, an engineering calculation showed that the low pressure C0-2 system could maintain a minimum concentration with tne six dampers open.
The subject dampers (VS-D-85A and B, 89A and B, and 90A and B) originally had a 1.5 hour5.787037e-5 days <br />0.00139 hours <br />8.267196e-6 weeks <br />1.9025e-6 months <br /> fire rating.
During the first refueling outage (November 1980), these dampers were replaced with dampers having a 3 hour3.472222e-5 days <br />8.333333e-4 hours <br />4.960317e-6 weeks <br />1.1415e-6 months <br /> fire rating; this was done to comply with fire protection system upgrades.
In March, 1985, the licensee < informed the inspector that these same six fire dampers were discovered to have been installed without reconnection of the mechanism for 3!nkage to the Cardox system.
American Nuclear Insurers, in a letter dated September 9, 1985, recommended that the licensee reinstall the CO-2 actuation trip mechanism for all of these fire dampers.
The licensee then issued DCP 589 to reinstall the release mechanisms and make other minor changes to the C0-2 system in the mezza-nine.
Since that time, the licensee has performed a partial OST 1.33.13 three times as post-maintenance testing for testing for various mezzanine fire dampers in January, March and May, 1986.
Each test had unsatisfac-tory results in that several dampers failed to close upon CO-2 actuation.
MWRs submitted in each instance were not completed.
This represents a lack of emphasis on timely completion of maintenance work on fire pro-tection equipment.
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The inspector observed performance of a partial OST 1.33.13, Fire Pro-tection System Detection Instrumentation, on May 14, 1986, as a post-maintenance test for fire dampers VS-D-85A and 858.
Performance of the test resulted in the identification of failure cf three dampers to close, one damper which had been reset incorrectly, and one damper missing its latching mechanism.
The findings were as follows:
An MWR was issued on March 3, 1986, for damper VS-D-90B and had not
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yet been worked as evidenced by the presence of the orange Work i
Request Submitted Tag and the failure of the damper to close during the test.
VS-D-89B and VS-D-283 failed to close when required for unknown
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reasons.
The licensee initiated followup actions.
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The bottom half of damper VS-D-85B failed to close during the test;
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it was later discovered during the resetting of the dampers that the wire cable which attaches the McCabe link to the damper was
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incorrectly positioned.
This caused the damper to hang up on the cable. Apparently, the bottom half of the damper had been reset
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incorrectly after maintenance while the top half was reset correctly
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and closed as required during the test.
The bottom damper was reset and tripped to verify that if it had been set correctly, it would have tripped when required.
VS-D-89A was discovered in the closed position after the test but
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operators were unable to reset the damper because the latch mechan-
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ism was missing.
A search of the area failed to locate the latch,
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and the licensee could not determine whether it was present before i
the test began.
Currently the damper is in the closed, safe posi-
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tion.
The purpose of OST 1.33.13 is a semi-annual test to verify the operabil-
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ity of fire detection instrumentation in areas such as the RHR Platform, Cable Spreading Mezzanine, Cable Penetrations, and the Auxiliary Feed i
Pump Area.
The OST cover sheet references the applicable technical specification as TS 4.3.3.6.1 and 2 and TS 4.7.14.2.b and c.
Fire de-i
tection instrumentation, sprinkler and spray systems are contained in these technical specifications, respectively.
Since this OST results
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in actuation of the Cardox system and the damper closure, it is routinely l
used as a damper post-maintenance test.
OST 1.33.10, CO-2 Fire Protection System Test is an 18 month test whose purpose is to verify the operability of the CO-2 system automatic con-trols, alarm annunciators, condition of nozzles, hoses, pipe and auto-matic door closing devices.
This OST references TS 4.7.14.3.b.1 and 2, which govern the low pressure CD-2 system, which specifically includes the verification that the ventilation dampers actuate manually and auto-t matically upon receipt of an actuation signal.
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f The licensee was already conducting an hourly fire tour of the cable mezzanine area per TS 3.7.15, Fire Rated Assemblies, until all of the structural steel caa be coated to upgrade its fire barrier rating to 3 hours3.472222e-5 days <br />8.333333e-4 hours <br />4.960317e-6 weeks <br />1.1415e-6 months <br />.
following the above finding, the licensee initially failed to TS3.744.3,LowPressureCO-2 System,whichrequirest
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dampers tol actuate automatically upon receipt of a signal to ensure an adequate CO-2 concentration in the fire area for about 20 minutes.
with all of the fire protection system OSTs.The overlap of the confusion over the applicable TS action statements.This overlap can lead to It is presently possible for personnel to perform one ~0ST with satisfactory results and be in compliance with the TS referenced in the procedure but be unaware
,that components which might have failed during the test performance are governed under a different TS.
In this situation, it is possible for
a TS LC0 to be violated.
The licensee is aware of this matter and is currently in the process of revising the fire protection surveillance tests.
, Unresolved' Item (85-11-01) is tracking the repair and successful testing of VS-D-858 and 90B.
This item will remain open until OST 1.33.10 is satisfactorily completed.
5.
Review of Reactor Cavity Seal (IE Bulletin 84-03)
a.
Scope of Review A Region-based specialist reviewed the Reactor Cavity Seal Design, as
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submitted by the licensee under reference 1 in response to IE Bulletin 84-03, to evaluate the potential for failure and to determine if the licensee had:
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(1) Identified the worst credible failure.
(2) Evaluated the consequences of such failure.
(3) Implemented procedures to mitigate the consequences of seal failure prior to fuel movement.
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b.
References (1) Letter from Duquesne Light Company to USNRC, Region 1, " Beaver Valley Power Station, Unit 1, IE Bulletin 84-03, dated September 11, 1985, with attachments as follows:
(a) Test Reports by Combustion Engineering Inc., Development De-partment:
TR-ESE-634, " Reactor Vessel Pool Seal Pin Pull Out Test",
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issued 9/28/84.
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TR-ESE-635, " Reactor Pool Seal Proof Test", issued 9/28/84.
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TR-ESE-632, Rev. 1, " Reactor Pool Seal Proof Test", issued
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9/27/84.
TR-ESE-626, Rev. 1, " Reactor Pool Sea: Load Test", issued
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9/5/84.
(b) Test Reports by Impell Corporation No. 03-1290-1104, " Experimental Verification of the Pres-
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ray Reactor Cavity Liner Seal for the Beaver Valley Power Station, Unit 1, issued August, 1985.
No. 03-1290-1108, " Experimental Verification of the Pres-
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ray Refueling Cavity Liner Seal for the Beaver Valley Power Station, Unit 1, issued September, 1985.
(2) Duquesne Light Company Analysis No. 8700-DSC-157D, dated 8/1/85,
" Drain Pipes", to calculate draw down rates (3 sheets).
(3) Combustion Engineering Power Systems Drawing No. E-6884-630-007, Revision 2, " Reactor Cavity Water ~ Seal Assembly and Installation",
dated 9/26/84, (2 sheets).
(4) The Presray' Corporation Drawing No. PR9213, " Inflatable Pool Seal Assemblies, (Sheet 1 of 2 for PRS 716 type seals).
(5) FSAR Section 9.12, " Fuel Handling System", for BVPS-1.
(6) FSAR Figure 9.12-1, " Fuel Transfer System", Beaver Valley Power
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Station, Unit 1, Revision 1 (1/83).
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Discussion
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(1) While the seal type and seal assembly is similar to that of Haddam Neck (Presray, 2 continuous rubber rings with a seal plate in be-tween), the Beaver Valley seal has the following advantages over the Haddam Neck seal:
Better surface contact for seal on RV flange side and cavity
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liner (2" vs 1-5/8").
The seal flange will have reinforcement pins which will stiffen
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the flange and contribute significantly to the push through resistance of the seal.
Tests Ref. 1(2) have shown that the safety factor against push-through is 9 as compared to 1.3 for the same seal without the pins.
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Twenty-four vertical plates support the horizontal seal plates
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and are also used to hold down the two seal rings by intercon-nocting the plates and the seal rings via bolts which are in-serted vertically into the flange of the seal.
This support arrangement stiffens the entire seal assembly and aids in the overall push through resistance of the seal.
(2) Assuming a Haddam Neck type failure of the seal ring for Beaver Valley, the time of discharge for the refueling cavity water can be estimated. The flow rate through the failed seal area is pro-portional to the seal gap and the volume of water to be discharged.
The water volume ratio is:
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= 1.25 The gap ratio = 2.5" = 1.25 EU'
Time ratio = 1.25 x 1.25 = 1.5625.
The discharge time for BV-1, therefore, 1.5625 x 20 = 31.25 minutes.
The licensee assumes a conservative leak rate of 1570 gpm which yields 159 minutes for the discharge time.
In the worst case, Haddam Neck type failure, there is still sufficient time to transfer fuel elements in transport to the safest location and to close the fuel transfer canal gate valve to prevent further water loss from the spent fuel (SF) pool.
(3) The licensee is going to add a cofferdam between the refueling cavity and the transfer canal to prevent water in the SF Pool from draining below the 743'-10" level.
At this water level, stored spent fuel elements would remain covered by approximately 2-1/2 feet of water.
(4) Water in the refueling transfer canal would drain below the bottom level of the refueling cavity at elevation 738'-10".
Any fuel in the upended position would be exposed 2-1/2 feet at this level.
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Conclusions
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Test information and results provided by the licensee should pre-clude failure of the reactor cavity seal at Beaver Valley, Unit 1.
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If a Haddam Neck type of failure occurred, there would be sufficient
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time to act to prevent exposure of spent fuel elements to air.
Spent fuel stored in the SF Pool would never be exposed to air due
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to the new cofferdam which the licensee will install under DCP 706.
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Emergency procedures have been prepared to provide guidance should
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a decreasing water level occur in the refueling cavity.
Based on the above review results, the inspector has no further
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questions on the adequacy of the Beaver Valley, Unit I reactor cavity seal.
6.
Engineered Safety Features (ESF) Verification The operability of the Low Head Safety Injection and Outside Recirculation Spray Systems were verified during the week of May 12, 1986, by performing walkdowns of accessible portions that included the following as appropriate:
a.
System lineup procedures matched plant drawings and the as-built con-figuration.
b.
Equipment conditions were observed for items which might degrade per-formance.
Hangers and supports were operable.
c.
The interior of breakers, electrical and instrumentation cabinets were inspected for debris, loose material, jumpers, etc.
d.
Instrumentation was properly valved in and functioning, and had current calibration dates.
e.
Valves were verified to be in the proper position with power available.
Valve locking mechanisms were checked, where required.
No deficiencies were identified.
7.
Surveillance Testing To ascertain that surveillance of safety related systems or componer ts is being conducted in accordance with license requirements, the inspect or ob-served portions of selected tests to verify that:
a.
The surveillance test procedure conforms to technical specification re-quirements.
b.
Required administrative approvals and tagouts are obtained before initi-ating the test.
Testing is being accomplished by qualified personnel in accordance with c.
an approved test procedure.
d.
Required test instrumentation is calibrated.
e.
LCOs are a.et.
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f.
The test data are accurate and complete.
Selected test result data was independently reviewed to verify accuracy.
g.
The test provides for independent verification of system restoration.
h.
Test results meet technical specification requirements and test discre-pancies are rectified.
i.
The surveillance test was completed at the required frequency.
j.
Portions of the following test were observed:
OST 1.33.13, Fire Protection System Detection Instrumentation, May
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14, 1986.
OST 1.24.6, Auxiliary Feed Pump Auto Start Test, May 17, 1986.
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TOP 86-12, Leak Check of RCS Vent Valves, May 17, 1986.
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OST 1.11.4, Accumulator Check Valve Test, May 17, 1986.
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BVT 1.5-1.21.2, Trevitest Method for Checking Major Steam Safety Valve Setpoint, May 16, 1986.
(1) The inspectors witnessed portions of the main steam safety valve setpoint check on May 16, 1986.
This test was performed using the Furmanite Trevitest System with the reactor operating at about 35%
power.
The inspector noted that each valve (manufactured by Dresser, 15 total) was lifted three times to prove data reproducibility.
After each lift, the safety valves properly reseated and displayed no evidence of any mechanical problem.
Technical Specification 4.7.1.1 requires that a sampling of the valves be tested to ensure that they lift within plus or minus 1%
of the specified setpoint.
If any are outside of this band, the sample size is increased.
Since the first four valves tested lifted low (conservative), all were tested. The results identified seven with low lift setpoints and three with high as-found setpoints.
Appropriate adjustments were made and each of the above valves re-tested.
The inspector identified no concerns.
(2) On May 17, 1986, the inspector observed selected portions of OST 1.11.4, Accumulator Check Valve Testing, which verifies valve leak tightness with corrected leakage required to be less than or equal to 8 gpm.
The test is performed during the plant shutdown process and allows the accummulators to be isolated and the check valves to be tested utilizing the accumulator test line and various flow and pressure indicators to determine individual valve leakage. The results are then corrected for normal operating pressures.
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The inspector reviewed the final test results and noted that the corrected leakages were all satisfactory. However, the inspector questioned the validity of the leakage measurements on the A accumu-lator check valves.
The measurements taken during the test indicate a greater leakage flow through the configuratior containing two check valves than that through one valve. A set ad problem con-cerned the portion of the test where leakage was measured by pres-sure increase to determine the leakage source.
In each such pres-sure measurement there was evidence of in-leakage into the system via flow indicators, but no pressure increase was recorded.
This indicates that the test hold time was insufficient for the leak rate to pressurize the volume of piping involved.
At the conclusion of the inspection period, the licensee was still in the process of evaluating the test date for acceptability.
During test performance, it was noted that two of the three RCS pressure indicators had expired calibrations (less than one month)
and the third indicator was being calibrated.
The licensee chose to continue with the OST using an out-of-calibration indicator (PI-RC-403 due May 14, 1986) and to later correct the result as neces-sary based on the degree of error found when the indicator is cali-brated.
A second problem involved three of six accumulator test line isolation valves (M0V-SI-850B, C and F) that were electrically inoperable and had to be manually opened and closed by operators in containment for purposes of completing the test to allow con-tinuation of the cooldown for refueling.
M0V-SI-850B was red-danger-tagged with an outstanding MWR since April 30, 1985, for motor prob-lems and M0V-SI-850C and F would not fully open from the Control Room and thus, had to be opened and closed remotely.
MWRs were issued and re-issued as each case warranted.
Correct performance of accumulator check valve and RCS pressure isolation valve leak tests is currently being tracked as Violation (85-02-01).
The violation was a result of the licensee's failure to correct the leakage measurements for full system pressure under normal operating conditions in accordance with ASME Section XI Sub-
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section IWV-3420, and was last updated in NRC Inspection Report 334/85-27.
The inspector reviewed both OST 1.11.4 and 1.11.16 and found the method of leakage rate correction for full system pressure to be correct. However, this item will remain opr.n pending success-ful completion of OST 1.11.16 and licensee investigation into the i
questionable data gathered by OST 1.11.4.
(3) TOP 86-12 had been developed to determine which Reactor Coolant Vent
System (RCVS) valves were leaking resulting in a high pressure alarm.
This test was performed while in Mode 3.
The key parameter observed was pressure indication, PI-RC-104, which provides RCVS pressure l
as sensed between Vessel Vent and Pressurizer Vent connections.
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The inspector observed performance of TOP 86-12, which was only partially completed.
The test was initiated by venting pressure off PI-RC-104 by opening and shutting S0V-RC-104, to establish a baseline pressure of zero psig.
The next step was to record an expected pressure increase to approximately 500 psig on PI-RC-104.
However, this expected pressure increase was not experienced after 2-1/2 hours and the test was discontinued.
Discussions with plant management indicated that since the leak rate is very small, the station is evaluating other options for identi-fying which of the SOVs is experiencing the slow leak.
8.
In-Office Review of Special Reports The inspector reviewed a Special Report, dated April 22, 1986, which concerned an inoperable Auxiliary Building Ventilation System Radiation Monitor, RM-VS-109.
This special report is required by Technical Specification (TS) 3.3.3.1.b because RM-VS-109 was inoperable for a period greater than 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br />, from April 10 to 21, 1986.
Investigation by the licensee and vendor, Eberline In-struments, identified a failure on the memory board.
The unit software was replaced with an updated version and the monitor was returned to service after successful post-maintenance surveillance testing.
Similar radiation monitors will also have updated software units installed.
During the period when RM-VS-109 was inoperable, alternate monitoring instrumentation was available.
9.
Inoffice Review of Licensee Event Reports (LERs)
The inspector reviewed LERs submitted to the NRC:RI office to verity 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-mined whether further information was required from the licensee, whether generic implications were indicated, and whether the event warranted onsite followup.
The following LER was reviewed:
LER 86-03:
Inoperable Diesel Area Fire Detection System This item was discussed at length in NRC Inspection Report 50-334/86-06, de-tail 9.
The inspector reviewed the LER for accuracy and noted that short term corrective actions have been implemented.
Long-term corrective actions are being tracked as Violation (86-06-04).
10.
Fuel Assembly Design Specifications Technical Specification 5.3.1 contains a brief qualitative description of the fuel assemblies used at BV-1.
Included is a statement that each assembly contains maximum total weight of 1766 grams uranium.
On April 25, 1986, Westinghouse (fuel vendor) informed DLC that some assemblies loaded in Zone 8 contained up to 10 additional grams.
This determination was the result of a change in the method used to weigh each individual fuel rod, to improve
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accounting procedures. Westinghouse also informed DLC that this did not im-pact any of the nuclear operation characteristics or the validity of the safety analysis.
The inspector discussed this item with the NRR License Project Manager and confirmed the vendor's' conclusion that no safety issue was involved.
DLC provided a formal safety evaluation to justify continued operation with the uranium rod weight discrepancy to NRR in a letter dated April 29, 1986.
The conclusions were found to be acceptable.
The licensee also stated that a technical specification change request would be submitted to correct the weight discrepancy.
The inspector had no further concerns.
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.