IR 05000334/1986018
| ML20203N123 | |
| Person / Time | |
|---|---|
| Site: | Beaver Valley |
| Issue date: | 09/04/1986 |
| From: | Lester Tripp NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION I) |
| To: | |
| Shared Package | |
| ML20203N107 | List: |
| References | |
| 50-334-86-18, NUDOCS 8609230152 | |
| Download: ML20203N123 (24) | |
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U. S. NUCLEAR REGULATORY C0pWISSION
REGION I
Report No.
.50-334/86-18
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Docket No.
50-334 Licensee:
Duquesne Light Company
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One Oxford Center 301 Grant Street l
Pittsburgh, PA 15279 Facility Name: Beaver Valley Power Station, Unit 1 I
Location:
Shippingport, Pennsylvania
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I Dates:
August 1-27, 1986 f
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Inspectors:
W. M. Troskoski, Senior Resident Inspector
A. A. Asars, Resident Inspector
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L. J. Prividy, Resident Inspector, BVPS Unit 2
'J. E. Beall, Senior Resident Inspector, BVPS Unit 2
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J. A. Robertson, Resident Inspector, Maine Yankee D
F. Li roth, Project Engineer, DRP 3A i
Approved by: g.(.
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k. E. Trit $, Chief, Reactor Projects Section 3A
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Inspection Summary:
Inspection No. 50-334/86-18 on August 1-27, 1986 i
Areas Inspected:
Routine inspections by the resident inspectors (400 hours0.00463 days <br />0.111 hours <br />6.613757e-4 weeks <br />1.522e-4 months <br />) of licensee actions on previous inspection findings, outage activities, housekeeping,
i fire protection, radiological controls, physical security and allegation followup,
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outage surveillance testing, the CILRT, startup recovery, control of Design Change
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Package open items, miscellaneous safety issues and hydrogen recombiner modifica-
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tion testing.
Results: One violation was identified (failure to administrative 1y control keys, detail 4.c).
Outage recovery and startup activities were found to be well con-
trolled.
Cold shutdown plant configuration control over required systems and com-
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ponents met regulatory requirements, however, areas were identified where further improvements are needed (detail 7.b) in configuration control for other equipment.
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8609230152 860909 PDR ADOCK 05000334 i
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TABLE OF CONTENTS Pa$Le 1.
Persons Contacted....................................................
2.
Plant Status.........................................................
3.
Followup on Outstanding Items........................................
4.
Plant Operations.....................................................
a.
Outage Activities...............................................
b.
Plant Security / Physical Protection..............................
c.
Radiation Controls..............................................
d.
Plant Housekeeping and Fire Protection..........................
5.
CILRT................................................................
6.
Outage Test Procedure Review.........................................
7.
O u t a ge Re c o v e ry......................................................
8.
Design Change Package Open Item Contro1..............................
9.
Miscellaneous Safety Issues..........................................
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10.
Hydrogen Recombiners.................................................
11.
Diesel Generator No. 1 Monthly Test..................................
12.
Exit Interview.......................................................
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DETAILS
- 1.
Persons Contacted During the report period, interviews and discussions were conducted with mem-bers of licensee.nanagement and staff as necessary to support inspection ac-tivities.
2.
Plant Status Unit 1 completed its Fifth Refueling and Modification Outage and entered Mode 2 to conduct Hot Zero Power Physics Testing on August 23, 1986.
A manual reactor trip was initiated from 3% power at about 1:05 p.m., on August 26, 1986, after the four control rod clusters associated with shutdown bank A, Group 2, dropped into the reactor.
At the conclusion of this inspection period, the plant was operating at 30% power.
3.
Followup on Outstanding Items The NR.C Outstanding Items (OI) 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) Unresolved Item (86-04-01): Determine cause of Vital Bus 3 circuit board terminal problems.
During the course of this inspection period, several Vital Bus 3 power fuses were blown due to a mis-sequence firing of the thyristor.
The licensee, with the aid of the Cyberex vendor representative, disassembled the No. 3 inverter and found evidence of arcing on the ground strip from the thyristor logic control board. The arcing occurred at a loose connection between the ground strip and the ground bus bar, which was subse-quently tightened.
Inspection of the No. 4 inverter also found evidence of minor arcing.
The station is planning to modify the preventive maintenance program to provide for a refueling outage frequency check of these components.
As this appears to have been the root cause of the inverter malfunction, this item is closed.
(Closed) Unresolved Item (85-06-04): Develop 18 month OST test conduct program guidance.
This item is discussed in detail 6 of this inspection report and is being administrative 1y closed because of program changes and different concerns identified during the course of this inspection.
Discussions with plant management indicated that significant portions of these procedures would be rewritten to incorporate lessons learned.
(Closed) IFI (85-16-01): Determine whether a seismic event could cause the flux mapping system to rupture the seal table pressure boundary.
Information Notice 85-45 detailed a design deficiency identified at another Westinghouse
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NSSS facility.
Because the exact configuration of these components are site specific, licensees were requested to perform an inspection of their system and perform any analysis necessary to verify that an adverse interaction would not take place during a design bases earthquake.
The inspector reviewed EM 61558 which performed the seismic analysis.
It concluded that, based on the BV-1 configuration, calculations showed that no interaction between the seal table and surrounding supports would occur.
This item is closed.
(Closed) Unresolved Item (84-33-03): Investigate possible containment integ-rity violation during startup from Fourth Refueling Outage.
Licensee correc-tive actions were confirmed during the augmented inspection discussed in de-tail 7 of this report.
(Closed) Unresolved Item (86-08-03): Use of parts from a non-safety component on a safety-related component without a 10 CFR 50.59 review.
The component in question was a mechanical latch that was removed from a Category 2 motor generator set breaker and used in a Category 1 reactor trip breaker.
Engi-neering Memorandum 61859 dated June 24, 1986, determined that the stop plate function can be considered non-safety-related as it does not impact the ability of the reactor trip breaker to open.
This item is therefore closed.
(Closed) IFI (84-33-07): Verify maintenance of personnel access pathways dur-ing the Fifth Refueling Outage for the containment airlock.
The inspector verified that these pathways were kept clear throughout the entire outage and especially during the high activity periods that included material removal for Type A testing and containment closecut.
Licensee actions were satisfac-tory and this item is closed.
(Closed) IFI (86-05-06): In response to Generic Letter 84-12, DLC submitted a copy of their Process Control Program (PCP) to NRR for review.
During this inspection report period, it was determined that DLC had developed another PCP which had not been submitted to NRR, and neither had the licensee per-formed evaluations to assure that vendor supplied data could be used to assure compliance with the regulations.
By letter dated August 1, 1986, the revised PCP was submitted.
Included in this submittal, were the results of the DLC Engineering section's independent review of the Atcor Supply data which was
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subsequently incorporated into the Beaver Valley, Unit 1 Operating Manual through the technical specification required review and approval process.
This item is closed.
(Closed) Unresolved Item (84-18-01): Licensee to take corrective actions to ensure that reportable events are properly identified.
This item was initi-ated because, for about one month, the licensee had been delinquent in pre-paring a required incident report on fire detection instrumentation test de-ficiencies.
The inspector reviewed SAP Chapter 13, Preparation of Draft In-cident Reports, Unit Off Normal Reports and Conduct of Critiques.
The licen-
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see has instituted a requirement for preparation of Unit Off Normal Reports
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(UONRs).
These reports document off normal plant conditions or events which
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do not meet the criteria for an Incident Report yet are of a nature that they may be used for data collection and evaluation of plant occurrences.
Since
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creation of the UONR, station personnel more closely evaluate abnormal plant conditions.for reportability and therefore, are no longer likely to neglect preparation of the necessary reports.
The inspectors continually review UONRs, Incident Reports and LERs and have found no further deficiencies.
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 and selected outage work activities.
Included in these reviews were plant radiation monitors, nuclear instru-mentation systems, onsite and offsite emergency power sources, control of boration and dilution flow paths, containment integrity and ventila-tion requirements, decay heat removal, and availability of necessary engineered safety features systems. 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.
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
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were witnessed and staffing requirements confirmed.
Except where noted below, the inspector comments or questions resulting from these daily reviews were acceptably resolved by licensee personnel.
1.
While heating the reactor coolant system to 160 F with pump heat on August 7, 1986, the licensee received a pressurizer safety valve tail pipe high temperature alarm and PRT high level alarm indicating leakby.
Apparently, the pressurizer safety valve (RV-RC-551C) had indication of a bellows failure. The licensee subsequently cooled the plant down and drained the pressurizer to about 20% to replace the failed valve.
Discussions with test personnel indicated that this valve had been sent offsite during the outage for the periodic testing required by TS 4.4.3.
Followup to identify the cause of the RCS safety valve failure is Unresolved Item (86-18-01).
It was replaced with a qualified spare manufactured by Target Rock.
The inspector reviewed the test certificates to verify that the left setpoint had been set to the TS value of 2485 psig plus or minus i
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During subsequent plant heatup and pressurization to 2235 psig,.an operations ~walkdown of the RCS identified a steam leak from the-flange of RV-RC-551C.
The plant cooled down and depressurized.
The licensee found that the flexitallic gasket had been accidentally crimped during installation of the spare valve. After replacement, a second walkdown at operating temperature and pressure conditions confirmed satisfactory repair.
2.
After experiencing several electrical problems with "A" train motors on August 5, 1986, and identifying an additional problem associated with starting the A reactor coolant pump, the licensee determined that the probable root cause was due to an inaccurate control room meter indication for the 1A 4KV Bus.
The meter which normally reads 0 to 130 volts for the full range 4160 volt bus was found to be about 4 volts low.
In addition, some of the pump relay overcurrent-protection setpoints were found to be set in the low end of the. band, which when coupled with the high inrush current needed to obtain the same power level at the lower voltage, resulted in the spurious trip. The relay protection setpoints were reset at the upper end of the band. The voltage meters were subsequently calibrated and are to be entered onto a periodic test schedule.
3.
A spurious safety injection occurred during the No. 1 Diesel Genera-tor Auto Load Test (OST 1.36.3) on August 8, 1986, with.the reactor in Mode 5, that activated only Train B components.
No water was injected into the reactor because the SI pumps had been previously disabled per procedure.
The operator placed the SSPS switch for Train B in Test, while the SSPS multiplexer was in the A+B position for an unrelated reason.
This resulted in multiple control room alarms, as the SSPS indication alternated between the two trains.
The operator was erroneously directed to return the Mode switch to Operate which resulted in a Train 8 SI on low steam pressure due to the block not being reinstated.
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The SSPS was immediately reset.
A critique of the event also iden-tified a test deficiency in that OST 1.36.3 de-energized two closed valves from the RWST to the charging pump suction line that were part of the boron injection path.
Procedures were revised to pre-vent recurrence.
4.
During a tour of the Control Room on August 15, 1986, the inspector noted that I&C technicians had been instructed to insert dummy sig-nals into the A steam generator narrow range level instrumentation system. This was being accomplished per 0M 1.24.4T, Draining and Refilling Steam Generators, to lower conductivity prior to startup.
It cautions that the steps used to insert the dummy signals cannot be performed when the plant is operating in Modes 1 or 2.
A signed double verification of the restoration steps are provided.
At the time of this evolution, the plant was in Mode 4 with reactor coolant temperature at 340 _ __ _
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Since the SG level instrumentation provides input to both the reac-i tor protection system and ESF logic cabinets, the inspector ques-tioned the use of a dummy signal that effectively bypassed this trip
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and ESF function.
A review of Technical Specifications 3.3.1.1,
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Reactor Trip System Instrumentation, and TS 3.3.2.1, ESF Actuation System Instrumentation, indicated that the SG low-low level trip was required only in Modes 1 and 2; which is consistent with the OM procedure caution.
However, Table 3.3-3, ESF Actuation, requires i
.it to be operable in Modes 1 - 3.
This inconsistency was brought to the. licensee's attention so that either the OM procedure or TS table would be revised.
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A second discrepancy was also discovered in Table 3.3-3.
Item 7c, Safety Injection (Start Motor - Driven AFW Pumps), requires the AFW 7'
system to be operable for all SI initiating functions and require-ments per Item 1 of the table.
Item 1, SI and Feedwater Isolation,
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j require all manual and automatic features to be operable when the plant is in Modes 1 - 4.
This is more restrictive than TS 3.7.1.2,
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Auxiliary Feedwater System, which only requires the pumps to be operable in Modes 1 - 3.
The licensee is also reviewing this item i
for possible revision.
Discussions with the Procedures Group indicated that OM 1.24.4T would be revised accordingly.
Long term corrective action to
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i strengthen the design change and modification system, which includes the use of dummy signals to instrumentation that does not have an
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installed bypass switch, is currently under way in the development i
of a Station Administrative Procedure.
Review of these actions to i
assure that the plant is not placed outside of its design basis by use of jumpers, lifted leads or unanalyzed bypasses to RPS and ESF j
instrumentaticn, is Unresolved Item (86-18-02).
i 5.
The inspectors observed portions of the reactor startup activities and core physics testing that started on August 24, 1986. While
conducting this testing, four RCCAs, of Shutdown Bank A, Group 2, j
dropped into the reactor at 1300 hours0.015 days <br />0.361 hours <br />0.00215 weeks <br />4.9465e-4 months <br /> on August 26, 1986..The
reactor was manually tripped from about 3% power per the abnormal
operating procedures.
Probable cause was identified as a failed I
circuit card in the rod control system power cabinet.
Shortly be-i fore the trip, a rod urgent alarm came in, signifying trouble with
the rod control system.
Before the operators could respond to clear the alarm condition, the four shutdown rods were observed to be at
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i the rod bottom position.
The plant was stabilized and appropriate j.
ENS calls were made.
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l After replacement of the suspect card (both stationary and moveable
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l gripper regulator and firing cards), the plant was restarted at 2330
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hours on August 26, 1986.
At the conclusion of this inspection, the plant was operating at about 30% power and continuing with the
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While in Mode 2, a problem arose concerning the actual position of rod F2 which is in Control Bank A (C8"A").. C8"A" had been pulled to 228 steps (operational " full out" position) per the group step counters. The individual rod positions (RPI) for all rods in C8"A" were within plus or minus 12 steps per technical specifications except for rod F2.
The licensee suspected that the RPI'was the problem. To verify this, TOP 86-34 was performed.
A visicorder was installed to monitor the stationary gripper coil voltage profile for CB"A", Group 1 rods (F2, B10, K14, P6) only.
The object of the test.was to withdraw these rods several steps to the " full out" position of 230 steps and compare the voltage profile from the
.visicorder traces. Vendor data had been provided which showed a unique inflection on the voltage profile for the stationary gripper coil when rods are at 230 steps. Only CB"A" Group 1 rods were moved during this test since the lift coil disconnect switches for CB"A" Group 2 rods were opened per the procedure.
The inspector observed the performance of TOP 86-34.
The voltage profile for all four rods was very similar with the noted unique inflection which indicated the rods were in the " full out" position of 230 steps.
The RPI for rod F2 was recalibrated satisfactorily and was now within plus or minus 12 steps when compared to other rods in CB"A".
All lift coil disconnect switches were returned to normal and the inspector considered these operations satisfactory.
b.
Plant Security / Physical Protection Implementation of the Physical Security Plan was observed in various plant areas 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 Adequate lighting was maintained.
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Security Allegation Followup Region 1 received a letter claiming that a set of security keys are readily accessible and not adequately controlled by the station.
It was stated that the keys were kept in a locker located in the Administration Building, and accessible to anyone with the building master key.
Through discussions with security personnel, the Administration Building custo-dian, and inspection of various key lockers, the inspector determined that protected area and vital area security keys were not stored in this offsite location.
The storage of any other keys is of no concern for meeting the requirements of 10 CFR 73, Physical Protection of Plants and Materials.
No further inspection followup for this allegation is pianned.
c.
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.
On July 29, 1986, NRC license examiners observed three individuals (one radcon and two maintenance technicians) obtain keys from the locker in the NSS office in the Control Room by turning the combination dial ap-proximately one quarter turn, removing the key and signing them out.
They then closed the door and turned the combination dial approximately one quarter turn in the opposite direction.
There was no shift super-visor in the office at the time and a sign on the key locker clearly stated keys are to be given out only with supervisor approval.
This item was passed on to the resident inspectors for further followup.
TS 6.12.2 requires that each high radiation area access be controlled by locked doors and that the keys shall be maintained under the admini-strative control of the shift supervisor on duty.
The failure to do so as evidenced by station personnel's ready access to the key locker con-taining the high radiation area keys is a Violation (86-18-03).
During a tour of the PAB on August 11, 1986, the inspector found a posted high-radiation door to the IB Boric Acid Storage Tank Cubicle, closed but unlocked.
No one was present and the door was secured.
Discussions held with the Radcon Supervisor indicated that this event would be re-viewed with the Operations Department and that station controls would be strengthened.
The inspector noted that the frequency of locked door tours were increased to twice per shift for the duration of the outage, and that the station's policy in regard to each individual's responsi-bility was reinforced and clearly posted at the NSS key locker.
The inspector had no further concerns at this time.
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Plant Housekeeping ar.d Fire Protection Plant housekeeping conditions 16cluding 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 was also observed.
No discrepancies were identified.
5.
Containrent Integrated Leak Rate Testing a.
Previous Testing The last Containment Integrated Leak Rate Test (CILRT) was conducted on May 9-13, 1982, in accordance with BVT 1.1-1.47.2, Rev. O.
Two signifi-cant problems hampered the testing; an excessive leakage path into the River Water System thrcugh the Recirculation Spray heat exchangers and malfunction of the personnel airlock emergency access hatch equalizing valve which caused the airlock to become pressurized. Acceptable leak rate data was tsken for a period of 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />.
Using the Mass Point Analysis Method, a calculated leak rate'at the 95% upper confidence level of 0.0375 weig5t percent per day was obtained.
b.
CILRT Procedure Review The inspector reviewed BVT 1.1-1.47.2, isev. 2, Containment Integrated Leakage Rate Test, and verified technical adequacy and compliance with TS 3.6.1.2, 10 CFR 50, Appendix J, ar.d ANSI N45.4-1972, Leakage Rate Testing for Containment Structures for Nuclear Power Reactors.
The test procedure adequately provided the necessary prerequisite testing, system configurations, actual leak rate measurements, superimposed leak testing, radiation discharge permit for depressurization, and controls for return of equipment after testing.
The inspector noted that the licensee har, chosen to use the Bechtel Corporation Total Time Analysis method as ae-scribed in Topical Report BN-TOP-1 Rev. 1, Testing Criteria for Inte-grated Leakage Rate Testing of Primary Containment Structures for Nuclear Power Plants.
The report states that previous performance of this method has shown that the acceptability or unacceptability of the leak rate can be determined during the first four to six hours of the leak measurement portion of the test.
The BVT provides for a 12 hour1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> leak measurement period after which a determination will be made based on an overall re-view of test data as to whether the leak rate is satisfactory.
This time may be shortened at the discretion of the lead test engineer.
c.
Test Prerequisites The inspectors reviewed the following CILRT prerequisite tests to ensure that in each case, the test was adequately performed with acceptable re-sults and that any unacceptable conditions were repaired and accounted for prior to test commencemen __-_ - __- _ - - -
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BVT 1.1-1.47.1, Verification of Structural Integrity of Containment Line s%
and Concrete Structure.
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BVT 1.3-1.47.6, Containment Liner Bulge Monitoring.
BVT 1.3-1.47.4, Type B Leak Testing - Electrical Penetrations.
BVT 1.3-1.47.8, Type B Leak Test - Personnel Airlock BVT 1.3-1.47.9, Type B Leak Test - Mechanical Penetrations
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BVT 1.3-1.47.10 Type B Leak Test - Equipment Hatch Airlock.
BVT 1.3-1.47.11, Safety Injection and Charging System Containment Pene-
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tration Valve Integrity Test.
BVT 1.3-1.47.5, Type C Leak Test of Containment Isolation Valves.
BVT 1.3-2.24.7, Steam Generator Pressure Test.
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BVT 1.3-1.13.4, Recirculation Spray Heat Exchanger Leak Detection Test.
m BVT 1.47.1, Type B Leak Test - Personnel Airlock Door 0-Ring Seals.
BVT 1.47.11, Type B Test - Equipment Hatch Airlock Door 0-Ring Seals.
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The inspector reviewed the instrument calibration records for the resist-ance temperature detectors (RTDs), dewcels, pressure detectors, and superimposed leak rate panel.
All calibrations met the applicable ac-curacy requirements and were traceable to the National Bureau of Stand-ards.
During a tour of containment, the inspector verified that the Q
sensors were positioned as required.
No unacceptable conditions were identified.
BVT 1.3-1.47.6 was performed between May 23 and July 14, 1986, to monitor the existing bulges in the containment liner and to identify any new bulges. All bulges are measured and compared to the corresponding data from last outage.
There are a total of 23 measurable bulges; no new ones were identified.
Though the measurement data has not yet been compared to the previous data, the results will be included in the CILRT results report to the NRC.
Performance of BVT 1.1-1.47.1 revealed separation of the concrete
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(grouting) at the transition region between the dome and cylinder por-tions of the outside containment wall and two gouges in the transition
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region. The separations were identified between the following radial markings; R7 and R14, R18 and R24, R62 and R71.
The gouges were identi-fied at R11 and R66.
Each gouge contained a small triangular section of wood which was used during initial construction.
The wood appeared to have swelled and forced out the surrounding grouting.
Engineering
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Memorandum 61846 was issued.to resolve the significance of the separation
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The evaluation concluded that
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these defects in the grouting are insignificant and will not affect the
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N CILRT.
The EM also specified instructions for repair of the separations and gouges at a later time.
The inspector had no further questions.
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The inspector verified that danger and caution tags were appropriately placed on plant equipment involved in the test as required by the test procedure and OM Chapter 48, Conduct of Operations.
The inspector re-viewed several equipment clearance permits and verified that appropriate i
measures were taken to prevent inadvertent pump and valve operation.
q Performance of,BVT 1.1-1.47.4 on the electrical penetrations provided acceptable results; the majority of the penetrations had leakages smaller
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g than thi detection capability of the measurement instruments.
Only two penetrations Jere repaired and retested.
The "0" ring leak check for
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penetration 7G (blind flange inside containment) showed an as found leakage of 28.5 SCCM.
The "0" ring was replaced and subsequent leakages
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were acceptable. The leak test for penetration 13F identified a leakage s
of 308 SCCM.
Repairs reduced this leak rate to 25.2 SCCM.
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' 'BVT 1.3-1.47.8 was conducted on 7/29 and 7/30.
The first test of the personnel airlock indicated an excessive leak which required a limit switch adjustment on the outer door.
Repairs were affected and a retest
was successfu1 /40.8 SCFD).
Subsequent to the BVT, OST 1.47.1 was suc-cessfully performed.
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'During performance of BVT 1.3-1.47.11, the licensee was unable to pres-surize penetration 13 due to excessive leakage through TV-FP-107.
e r Saveral attempts to repair the valve before the CILRT were unsuccessful.
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Forfthe CILRT the spectacle flange immediately downstream of the valve
was ture.ed to serve as a: blank flange and the associated drain valve was
isolated. The inboard containment isolation valve is a check valve with l
an4as fiund leaktge of 0.436 SCFD.
This leakage was used as the Type
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CynaltyaddedtothetotalmeasuredleakrateoftheTypeAtest.
d.
CILRT Pe'eformince
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During the, course of the' test, the inspectors observed the final contain-ment close-out walkdown, data gathering and trending, leakage rate cal-
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culations, superimposed leakage test, and performed independent hand calculations of the leak rate using available raw data.
The following chronology summarizes the sequence of events:
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July 30, 1986 0230 Completed close-out inspection of containment 0630 Began containment pressurization 2200 Ctat recirc fan VS-F-1A tripped, started VS-F-1C 2230 Completed containment pressurization to 55.373 psia, at 78.85 F.
2300 Began stabilization hold July 31, 1986 0304 Completed stabilization period 0337 Commenced leak rate measurement 55.180 psia, 76.875 F 0934 Suspected leak at Recirc Spray HX to River Water system isolated at HX river water discharge valves MOV-RW-105A, B & C.
Increasing trend in containment moisture content August 1, 1986 0516 Initiated leak rate measurement 55.335 PSIA, 77.364 F 1516 Leak rate unsat., fan chillers still affecting temperature 1610 Continued adjusting chilled water flow to fans 1700 Chiller adjustment unsat., temp still increasing 2351 Isolate chilled water and secured fans August 2, 1986 0100 Ctmt temp and pressure stabilized 55.373 PSIA, 77.935 F 0237 Reinitiated leak rate measurement 55.372 PSIA, 77.871 F 1317 Completed leak rate measurement 55.359 PSIA, 77.909 F 1618 Began superimposed leak rate test, 4.6 SCFM l
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August 3, 1986 0035 Completed superimposed leak rate test, 4.6 SCFM 0235 Began depressurization 1113 Completed depressurization During the course of the test, the inspectors observed the response of
the containment wide range pressure indicators and recorders (PR-LM100A, PR-LM101, PI-LM-101A and PI-LM-101B) which were installed as a result of the TMI Action Plan Requirements.
The sensors and recorders closely tracked the containment pressure as indicated by test instrumentation.
Two items of information were noteworthy concerning the operation of the Containment Recirculation Fans.
These are the fan blade pitch setting and the fan motor overcurrent condition while at test pressure of 55 PSIA.
A test prerequisite was to adjust the fan blade pitch for all fans from the normal setting of 13 degrees to 7 degrees to prevent overloading the motor due to the denser containment air at test conditions.
The 7 degree setting appeared to work satisfactorily in the last CILRT.
The fan blade adjustment was done by the vendor (Joy).
However, the fan motors oper-ated in an overload condition for an extended time while at test pressure which indicates that future CILRTs should make further adjustments to blade pitch.
In the early stages of the test (on 7/30) while initially approaching test pressure with two fans operating, VS-F-1A tripped on overcurrent. The third unit (VS-F-1C) was started without incident.
The fan switchover had a minimal impact on the test.
e.
CILRT Results The inspector independently calculated leakage rates using raw data dur-ing the test to verify licensee preliminary leak rate estimates.
The results of these calculations closely agreed with the licensee's results.
The test acceptance criteria required that the measured leak rate (in-cluding the upper 95% confidence level) plus the penalty leakage at the initial test pressure (53 PSIA) be less than 75% of the maximum allowable leak rate of 0.10 weight percent per day.
Using the total time method of leak rate calculation, the licensee de-termined that measured leak rate with the 95% confidence level to be 0.012761 percent per day and the penalty leakage from the Type C testing to be 0.001496 percent per day.
These two values yield a total as found leak rate of 0.014257 percent per day.
These results are well within the acceptance criteria.
The inspectors noted that TV-FP-107 was repaired after the CILRT and subsequently passed the Type C test.
The leakage through this valve does not affect the as-found leak rate because the total penetration leak
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In the case of TV-FP-107, the inboard check valve had the smaller leak rate.
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The inspectors identified no further concerns.
6.
Outage Test Procedure Review a.
Beaver Valley Tests (BVTs)
BVTs are governed by Station Administrative Procedure (SAP) Sb, Test Group and Testing and Plant Performance Administrative Procedures (TPPs).
Specifically, TPP 5.1, Administrative Guidelines for Performing Tests, and TPP 6.1, Guidelines for Completing Test Results Reports (TRR), are
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applicable to the actual performance and approval of BVTs.
The inspector
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noted that TPP 5.1 adequately provides for the notation of test defi-ciencies and deviations and NSS notification for immediate resolution.
Also, the TRRs are structured so that a BVT cannot be approved if the test results are unsatisfactory.
If the results do not meet the accept-ance criteria, the deviation is identified and corrected; the test is reperformed until the results are satisfactory.
Each BVT TRR is reviewed by two additional reviewers other than the lead test engineer. The in--
spector reviewed the following BVTs to ensure that these administrative controls are being effectively implemented to assure each test is per-formed with acceptable results.
BVT 1.3-1.4).1, Rev. 5, Containment Isolation Valve Leakage Test Connec-tion Verification.
BVT 1.4-1.30.2, Rev. O, IST Exercising of (River Water) Check Va !ves RW-197 and RW-198.
BVT 1.4-1.13.5, Rev. 2, Inside Recirculation Spray Pump Test.
BVT 1.1-1.46.3, Rev. O, Wide Range Hydrogen Monitoring System Leak Test.
BVT 1.5-1.33.7, Rev. O, Halon System Nozzle Air Flow Test.
BVT 1.1-1.39.3, Rev.1, No. 3 Station Battery Charger Load Test and Bat-tery Service Test.
BVT 1.4-1.39.7, Rev. O, No. 2 Station Battery Capacity Test.
No discrepancies were identified.
b.
Maintenance Surveillance Procedures (MSPs)
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A review of completed 18 month MSPs was performed to verify proper lic-ensee review and approval, conformance to technical specifications, ac-curacy, completeness and resolution of test discrepancies.
A sample size t
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of 20 MSPs were chosen from the Main Steam, Main Feedwater and Auxiliary Feedwater Systems.
The inspector noted that these procedures were clearly written in a good format and easily followed.
Critique sheets provided a positive method of feedback and resulted in procedural changes when applicable.
One minor weakness noted was that some procedures stated that they could be performed in any plant mode; however, this is not true for all steps of the procedure.
The steps that cannot be per-formed are crossed out or changed by the technician performing the sur-veillance test.
This item was discussed with plant management to deter-mine whether prior supervisory approval should be obtained rather than leaving it to the discretion of the technician performing the test.
The inspector also reviewed MSP 4.03, ESF and Miscellaneous Safety Re-lated Instrument Valve Alignment and Calibration Verification, completed August 5, 1986.
The implementation of this procedure indicates that BV-1 has learned from other station's problems and implemented strong controls to assure proper instrumentation valve lineups prior to startup.
This is a good practice.
c.
Operation Surveillance Tests (OSTs)
The overall quality of the completed 18 month OSTs reviewed was found to be acceptable.
General observation and minor problems identified by the inspectors are as follows:
(1) Several examples were found where it was difficult to determine whether or not the specified acceptance criteria was met.
OST 1.11.15 requires the safety injection accumulator check valve to stroke fully open as verified in Step 22.
This step states "have test crew verify the following check valves fully open" and lists the six valve numbers.
There is no position indication on these valves.
During inspector observation of the OST, the check valves were easily verified to have fully opened by the sound of the flapper banging on the seat.
A second example is OST 1.30.8, where the acceptance criteria re-l quires the Auxiliary River Water Subsystem to provide at least 8000 l
gpm cooling water for at least two hours.
The flow rate is estab-I lished to an orifice, pump current and pump discharge pressure data are taken, and then the system is realigned to obtain the same pump discharge pressure.
The acceptance criteria is then taken to be no degradation of monitor parameters over the two hour run.
Also, a precaution step required that two component cooling water heat exchangers must be available and utilized, but the shift supervisor noted that only one heat exchanger was available due to I
the outlet valve inoperability on CC-E-1C.
The inspector questioned l
whether this affected the 8000 gpm acceptance criteria necessary
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for. successful test completion.
The licensee stated that the flow i
path.used was chosen for operating flexibility and did.not impact
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test acceptability.
An_0MCN was subsequently issued to clarify this.
l (2) _Some of the precautions and limitations could be worded more use-fully in that quantitative values could be given for specified parameters such as recommended by ANS 3.2.
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(3) A third general weakness identified on several OSTs was the pretest
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requirements to have "all valves in designated NSA positions as_de-termined by Control Room logs or flow diagrams." The many instances identified by the inspectors where the Control Room logs and flow diagrams contained discrepancies from actual alignments (as dis-cussed in detail 7.b of this inspection report), indicates that this is not a good practice.
The licensee stated that all such refer-
ences would be revised to specifically list the required alignment prior to the next refueling outage.
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Major 18 month surveillance tests witnessed by the inspectors to verify ~
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procedure compliance and that test methodology met the intent of the
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technical specifications, included the following:
OST-1.24.8, Auxiliary Feedwater Check Valve Test, conducted on.
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August 9, 1986.
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OST 1.36.4, No. 2 Emergency Diesel Generator Load Test, conducted on August 10, 1986, i
OST 1.11.16, Leakage Testing RCS Pressure Isolation Valve, conducted
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on August 11, 1986.
- OST 1.7.11, CHS and SIS Operability Test, conducted on August 11, 1986.
i OST 1.1.4, Containment Isolation Trip Test, Train B, conducted on
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August 8, 1986.
BVT 1.3-1.11.1, SI Auto / Manual Switchover-to Recirculation Mode l
Operability Test, conducted on August 8, 1986.
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No problems were identified by the inspectors during conduct of the above
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tests.
4.
7.
Outage Recovery An augmented inspection of the Station Outage Recovery was conducted from August 8 thru 18, 1986, as recommended by the Region 1 SALP Board (See IR 334/85-99, Page 31).
The inspection included extensive backshift coverage and focused on the conduct of control room activities, plant configuration control and completion of startup prerequisites.
Additionally, licensee ac-
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tions outlined in DLC letter of April 11, 1985, in response to the Notice of-Violation (See IR 334/85-03 and NRC letter dated March 19,.1985) were exten-
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sively reviewed to assess their effectiveness.
a.
Control Room Activities Throughout this portion of the inspection, the attitude of operations personnel was positive, cooperative and generally professional, especially when considering the duration of the outage.
For the most part, the reactor operators enforced the station policy on limiting access to the control board.
The inspectors also observed good involvement by the NSOF (an SRO) in both routine evolutions and outage testing.
The shift tech-nical advisor was often involved in performing calculations and tracking /
followup of startup open items.
Throughout this outage, the control room noise level was kept to a mini-mum.
This was achieved by moving the equipment clearance desk outside of the control room and establishing and enforcing administrative rules on personnel access. Additionally, the new control room carpeting has had a favorable impact by muffling the background noise level.
However, because of the physical layout of the control room, it did maintain a cluttered look.
Station management involvement was evident throughout this period. The
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. inspectors did note that unlike the last several refueling outages, the
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recovery was handled in a more disciplined fashion that lessened the
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" push to startup" problems previously observed.
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b.
Plant Configuration Control To ascertain whether the licensee was effectively controlling plant con-
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figuration, the inspectors conducted extensive walkdowns of various safety systems (main feedwater, main steam, the reactor coolant system,
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CVCS, safety injection, post-accident hydrogen control-and containment
depressurization system).
The inspectors compared as-found equipment clearances and valve positions with those indicated on various equipment
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clearance logs and control room status boards and prints. Many instances were noted where the drawings in the control room were not maintained current.
Though this problem has been minimized from a technical speci-
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fication impact by " hardening" required safety systems (such as clearly defining the boric acid addition flow path and placing caution tags on
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related valves), significant problems could still occur. A specific example observed by the inspectors occurred during performance of OST
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1.11.14, Full Flow Safety Injection Tests, when the operators erroneously
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i verified that the low head safety injection pump suction path was open through a review of control room prints when in fact it was not.
The operator manually started both low head safety injection pumps with the suction valves closed and ran the pumps for approximately 15 to 20 seconds before another operator observed the incorrect lineup and shut
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the pumps off before damage could occur.
Though these pumps are not re-quired to be operable when the plant is in cold shutdown, the impact to the station would be unfortunate should both have been damaged.
The inspectors noted that the licensee has changed the methodology by which system lineups are performed.
A complete system walkdown is now performed one time, with the second verification of critical valves pro-vided either by OSTs or a second walkdown where applicable.
The inspec-tors determined that this system is still weak in that some system walk-downs were initiated in early to mid-July, 1986.
The walkdown for some systems was not completed until over 30 days after it was initiated.
Consequently, the "NSA Deviation Review Log" which is performed to insure that the final system alignments contained no unacceptable deviations, has little value.
Though the licensee attempted to start the valve lineups after most of the system work was expected to be complete, alignments were often changed several times through equipment clearance work and ongoing outage testing.
This contributed greatly to the inability to maintain the con-trol room status board up to date. As an example, the inspectors found a charging pump discharge valve (CH-27) closed in the field, but indi-cated open on the control room print.
After extensive review of ongoing work activities, the licensee was able to determine that this valve was marked Of f-Log-Only.
Again, this component was not required with the plant in cold shutdown but reliance on control room prints to accurately reflect the position of this manual valve would have posed problems.
Towards the end of the outage and 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> prior to leaving Mode 5, the licensee had non-shift SR0s independently walk systems down to identify and correct deficiencies.
Inspector discussions with these individuals and plant management indicated that they identified the same type of problems as already discussed.
The inspectors concluded that the fol-lowing weaknesses still exist:
(1) Valve lineups in general, were started too early while significant work was still in progress.
These lineups, though adequate, were not maintained current as component positions are changed. Also, it could not be determined when a lineup was actually performed.
(2) Drawings in the control room were not always maintained current to reflect actual system alignment.
(3) The system of deviations is an administrative burden on supervisory personnel and is of little value as presently employed.
(4) The clearance system appears to be generally effective but is in-efficient; the restoration process is questionable.
The off-log-only process needs further examination because of the amount of work that remains on going throughout an outage.
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c.
Startup Prerequisities The inspectors reviewed Operating Manual Chapter 1.50, Station Startup, and the Startup Prerequisite List.
Prior to leaving cold shutdown, station management spent a considerable amount of time verifying that all of the prerequisites were complete and all surveillance testing up to date.
Prior to leaving cold shutdown, the inspectors observed completion of portions of the Containment Integrity Checklist and OST 1.12.4, Contain-ment Pressure Check for Air Leakage, on August 11, 1986.
This test ef-fectively monitored containment pressure by gathering temperature and pressure data for a four hour period to verify that there was less than'
a 0.1 psi differential corrected containment pressure over the time period.
This practice goes beyond completing valve lineups in assuring that no air in-leakage exists.
d.
Summary Many of the problems evident during the recovery from the last two re-fueling outages were successfully avoided during this recovery.
Plant configuration problems that did occur had little impact on plant safety because control over the required systems and components was administra-tively hardened.
Startup prerequisite reviews were extensive and thorough, though they were manpower intensive. This indicates that DLC management placed a high priority on the conduct of a smooth and error free startup.
Commitments made to the NRC in DLC letter of April 11, 1985, were met.
Discussions with senior management indicated that they were cognizant of the equipment and plant configuration control problems previously discussed, and that further improvements were actively being explored.
The inspector noted that further solutions would also have to account for the integration of Unit 2 activities.
This concern was acknowledged.
8.
Design Change Package Open Item Control The inspector reviewed the licensee's administrative procedures and several design change packages (DCPs) to verify that DLC has positive control over open items which remain after operational acceptance.
A DCP open item is any item remaining unresolved after. the DCP is turned over to the station and operationally accepted.
These items include, but are not limited to, con-struction open items, incomplete station turnover activities and any defi-ciencies identified during the preoperational testing.
The primary responsibility for tracking DCP open items changed in 1984 when the reorganization of the Engineering Departments took place.
Before that time, Station Engineering tracked all of the open items; but after the re-organization, Station Engineering no longer existed.
Nuclear Engineering and
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Construction Unit (NECU) was created and assumed the tracking of only those
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open items which related directly to engineering or construction.
The remain-
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ing station open items (those related to the Technical Services Group, Nuclear Training Group, Testing and Plant Performance, Station Maintenance Instrument and Control, and Station Operations) have been informally tracked by Planning and Outage Management (P&OM).
Currently, the general control over DCP open items is governed by Nuclear Engineering Management Procedure (NEMP) 2.8, Rev. 3, Handling of Design Change Packages, and Planning and Outage Management Manual (P&OMM) Chapter 23, Design Change Package Matrix and Open Items Programs.
NEMP 2.8 describes the engi-neering and interface controls in implementing a DCP.
P&OMM 23 establishes the methods and requirements of the DCP Matrix and Open Items Program.
It monitors milestones of engineering and installation with the DCPs which have been turned over as operationally acceptable.
The licensee is aware of the weakness in the program for DCP open items and is planning on developing and implementing new procedures for DCP handling and a tracking system for all DCP open items.
Completion is scheduled before the end of 1986.
Implementation of this DCP program and update of the DCP open items tracking list will be Unresolved Item (86-18-04).
9.
Miscellaneous Safety Issues a.
IE Bulletin 85-03, MOV Common Mode Failure During Plant Transient due to Improper Switch Settings The inspector informed the licensee that DLC letter of May 16, 1986, which contained their initial response to the subject bulletin was found to be inadequate by the Office of Inspection and Enforcement.
Specific-ally, because no additional differential pressure tests were planned, amplification of the switch setpoint establishment methodology would be needed.
This topic had been briefly discussed in Detail 11 of NRC In-spection Report 334/86-11.
The inspector's comments were acknowledged by the Senior Licensing Engineer.
b.
IE Bulletin 86-02, Static "0" Ring Differential Pressure Switches This bulletin was issued to alert licensees of potential problems with Series 102 and 103 differential pressure switches supplied by SOR, Inc.
for use as electrical equipment important to safety.
The inspector re-viewed licensing memorandum MD1NSM:2257 dated July 23, 1986, which indi-cated that a review of the Maintenance Equipment List and applicable technical manuals identified none of the subject model switches used at BV-1.
No further action is required and this item is closed.
c.
IE Information Notice 86-68, Potential Deficiency in Improperly Rated Field Wiring to Solenoid Valve This Notice detailed a design deficiency in field run cables to Valcor solenoid valves at several facilities. The field run cables that were terminated inside the valve body, housing a large energized solenoid,
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were subjected to a temperature range of 250 - 280 F for an extended period of time.
However, the wiring was found to have an insulation temperature rating of 90 C (144 F).
To correct this deficiency, Beaver Valley instituted DCP 690 and replaced the then existing 90 C wire with a length of 200 C wire for about 33 S0Vs in the plant.
Six of the SOVs on the reactor vessel vent system were to be upgraded for environmental consideration. While performing this work, the licensee determined that past problems with the 50V on the reactor hot leg sample isolation valve (TV-SS-105A1) appeared to be due to internal valve spring failure.
The failure mechanism of the valve springs was determined to be hydrogen embrittlement of the 17-7 ph stainless steel spring material.
Valcor Engineering Corporation informed the licensee of three instances at other PWR facilities where this particular material spring failure occurred after approximately one to two years of service when exposed to reactor chemistry water at temperatures above 440 F.
It was recommended that replacement springs of a cobalt based alloy (Elgiloy) be used as a re-placement material as it is not subject to hydrogen embrittlement.
Discussions with responsible engineers indicated that only three valves (TV-SS-105A1, A2, and TV-SS-106D) were subjected to this phenomena and required spring replacement during the Fifth Refueling Outage.
This work
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was done under the plant maintenance work request system and TER 124 was initiated to update drawing and technical manuals to show the new mate-rial as used.
None of the other valves indicated the type of degradation as evidenced by the successful Type C Leak Rate Test cond;.cted.
The inspector had no further questions at this time.
10.
Hydrogen Recombiners DCP 621 was initiated to upgrade the Environmental Qualification of the Hydro-gen Recombiners to IEEE Standard 323, 1974 edition.
The work on the Rockwell Hydrogen Recombiners included replacement of the control cabinets and a skid mounted blower unit, which included replacement of the positive blower with a centrifugal unit.
Initial post modification testing was conducted under OST 1.46.4, Six Month Hydrogen Recombiner Test, which recirculated blower flow rather than aligning the system to the normal pipe arrangement which pulls a suction and discharges into the containment atmosphere, due to outage conditions.
After pulling the initial vacuum on containment (down to about 9.4 psia) the 18 month surveil-lance test was conducted per OST 1.46.2, Post-DBA Hydrogen Control System Tests, which uses the normal flow path from and to containment.
Technical Specification 4.6.4.2.b.3 requires each hydrogen recombiner system to be demonstrated operable at least once per 18 months by verifying that the system is capable of producing a flow rate of greater than or equal to 50 standard a
I cubic feet per minute (scfm) when using containment atmosphere air at a pres-sure of less than or equal to 13 psia.
After extrapolating the data from the 9.5 psia atmosphere test pressure to something less than 13 psia, the licensee determined that both trains would fail to meet this criteri. _ _ _ _ _
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Additional testing indicated that the centrifugal blowers were not able to overcome the line resistances due to the weight loaded 2" swing check valves installed inside containment on both the suction and discharge lines.
To overcome the flow resistance offered by these valves, the licensee decided that a pipe and valve configuration change would be necessary.
Since the in-side containment check valve on the suction line does not function as an iso-lation valve, the-internals were removed and a new check valve installed out-side of containment downstream of the containment vacuum pump isolation valves to prevent air inleakage should a vacuum pump fail.
However, the discharge check valve does serve as a containment isolation valve and consequently, required the installation of a second ball valve outside of containment to provide double isolation.
This will require a technical specification change to Table 3.6-1, Containment Isolation Valves, which contains a description of each containment penetration.
After a series of conference calls between the licensee, NRR and Region 1, the description of the physical change as contained in the DLC Safety Evaluation of August 22, 1986, was found accept-able.
The licensee was granted verbal permission to restart the station while proposed operating license change request No. 130 was processed by NRR on an expedited basis.
The inspector reviewed both the Type C leak test data and subsequent system testing performed at 12.85 psia which indicated that there was about a 10%
margin above the minimum flow level specified in the technical specification.
The inspector walked down the modification and verified that the two addi-tional containment isolation ball valves were maintained locked closed and under administrative control.
A review of control room prints indicated that they had been updated in a timely manner to reflect this modification. The inspector determined that the licensee completed the modification and con-ducted the testing specified in the DLC letter of August 22, 1986, and formal approval of the technical specification change is under the jurisdiction of NRR.
11.
Diesel Generator No. 1 Monthly Test During the performance of OST 1.36.1, the governor for the No. 1 Diesel Generator was not properly responding to load changes.
Specifically, when the diesel generator governor control switch was placed in the raise position to increase load, load would continue to increase until the diesel generator governor control switch was placed in the decrease position.
Upon reversing the loading it would continue down in a like manner.
Close, dedicated opera-tor action was needed to prevent overload conditions during the governor's unstable operation.
The OST was considered unsatisfactory due to the uncer-tain manner in which the No. 1 Diesel Generator might perform when called upon to receive and power emergency loads.
The vendor was contacted and suggested that the OST be rerun at different governor speed droop setting.
The unsatisfactory operation had been conducted with a setting of 42.
The OST was rerun with the droop settings below 42 and
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slightly varying the load from a full load of 2850 kW.
This was done to ob -
tain proper governor response. A final setting of 38 was established and OST
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1.36.1 was then signed off as being acceptable.
12.
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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