IR 05000334/1990002
| ML20012D467 | |
| Person / Time | |
|---|---|
| Site: | Beaver Valley |
| Issue date: | 03/09/1990 |
| From: | Hernan R NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION I) |
| To: | |
| Shared Package | |
| ML20012D465 | List: |
| References | |
| 50-334-90-02, 50-334-90-2, 50-412-90-02, 50-412-90-2, NUDOCS 9003270375 | |
| Download: ML20012D467 (15) | |
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L U. S. NUCLEAR REGULATORY COMMISSION i
i REGION 1 i
50-334/90-02 DPR-66 Report Nos.:
50-412/90-02 License Nos.:
Licensee:
Duquesne Light Company One Oxford Center
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301 Grant Street
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Pittsburgh, Pennsylvania 15279 Facility Name: Beaver Valley Power Station, Units 1 and 2 f
Loi:ation:
Shippingport, Pennsylvania
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Dates:
January 1 - February 16, 1990 I
Inspector:
P. R. Wilsor., Senior Resident Inspector
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. Beaulieu, Resc+or Engineer Approved by:
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htovu 9 '7D
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R6n Hernen, Acting Chief
/Dath Reactor Projects Section No. 4B
Division of Reactor Projects inspection. Summary: Combined Inspection Report Nos. 50-334/90-02 and
_5_0-412/90-02 for January 1, - February M,1990..
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Areas Insrected:
Routine inspections by the resident inspector of licensee
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a:< ions on previous' inspection findings, plant operations, security, radiolog-
1 cal controls, plant housekeeping and fire protection, surveillance testing, maintenance, Unit 2 Recirculation Spray Heat-Exchanger design concerns,
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Fitness for Duty training and licensee event reports.
Results:
Overall, the facility was operated safely. One non-cited violation was iden-
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tified regarding the failure to perform required-time response testing on a safety related pressure transmitter (Section 7).
One unresolved item was
. identified concerning the Unit 1 Recirculation Spray Heat Exchanger river water radiation monitor branch lines not meeting General Design Criterion 57 (Section
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- 8).
The. licensee's Fitness for Duty training program was reviewed. No defici-
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encies were identified (Section 9). Weakness in Unit I housekeeping was iden--
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.tified (Section 4.6). Four previous NRC open items were reviewed and two items
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were closed.
-9003270375 900309 PDR ADOCK0500gf4
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TABLE OF CONTENTS Page v
1.
Pe rson s Conta cted.......................
2.
Summary of Facility Activities.-..............'..
3.
Status of Previous Inspection Findings (IP 71707, 92702, 92701)...:.....................
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Operational Safety (IP 71707, 71710, 40500, 93702)......
3 4.1 General
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4.2 ES F Wa l kd own......,................
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4.3 Operations..........................
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4. 4-Plant Security / Physical Protection.............
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4.5 Radiological _ Controls..................
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'4.6 Plant Housekeeping & Fire Protection.......,,..
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Surveillance Testing (61726)..................
8-N C.
Maintenance (r27C3)
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.7. -Unit 2 Missed Post Maintenance Test (71707, 93702)....
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8.
Unit'l Recirculation Spray Heat Exchanger River Water
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' Rad % tion Sample Line Design. Problem (93702, 37700)....-
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Fitness.for Duty-(TI 2515/104)................
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10.
Inof* tee Review of Licensee Event Reports (9071P., 40j00)...-
' 11. Un esolved Items.......................
- 12. -Meetings (30703).......................
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DETAILS 1.
Persons Contacted During the report period, interviews and discussions were conducted with members of licensee management and staff as necessary to support inspec-tion activities.
2.
Summary of Facility Activities At the beginning of the period, Unit I was operating at 50% power in a power ramp up mode following the Unit I seventh refueling outage. Unit 2 was operating at 85% power as part of a core life extension schedule. On January 6, Unit I reached 100% power and operated at that level until January 8 when a controlled shutdown was commenced due to unidentified Reactor Coolant System leakage in excess of Technical Specification requirements (see Section 4.3.2).
The shutdown was terminated at 68%
powr.
The unit returned to full power operation on January 9, and oper-ateci at that ievel until January 19 when a controlled shutdown was initi-ated to repair a 120 VAC vital bus inverter and a leaking relief valve on the Chemical Velume and Control System charging header (see Section 4.3.3).
On January 21, Unit I returned to power operation and operated at 100% power for the remainder of the period.
Unit 2 operated at 85% power until February 2 when power was reduced to 29% to allow for maintenance of the Main Feedwater Reg alating Valves and other balance of plant equipment.
Between February 5 and 12, Unit 2 was operated at 47% power as a fuel saving measure. On February 12, power was inc" eased to 90% and remained at that level for the remainder of the pertod.
3.
. Status of Previous Inspection findings The NRC Outstanding Items List wss reviewed with cognizant licensee per-sonnel.
Items selected by the inspector were subsequently reviewed through discussions with licensee personnel, documentation reviews, and field inspection to determine whether licensee actions specified in the Ols had been satisf actorily completed. The overall status of previously identified inspection findings was reviewed, and planned / completed 11cen-see actions were discussed for the items reported below.
3.1 (Closed)
Bulletin (50-412/85-00-03)
Motor operated valve common mode failures during transients due to wrong switch settings.
NRC Bulletin 85-03 was superseded by NRC Generic Letter 89-10. This item is administrative 1y closed.
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3.2 (Closed)
Unresolved Item (50-334/88-11-01; 50-412/88-07-01) Imple-ment program to resolve inadequate or lack of labeling of plant
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equipment deficiencies. A formal labeling program was developed and
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has been fully implemented by the licensee. The licensee assigned a i
licensed operator to oversee the program.
Notable progress has been made in regard to component labeling. The inspector had no further questions.
3.3 (0 pen)
Unresolved Item (50-334/87-07-02)
Ret.olved Auxiliary Feed-water (AFW) Pump 3A performance characteristics.
In May 1987, sur-
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veillance testing indicated that the differential pressure fvr the
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motor driven AFW pump 3A, while satisfying the Updated Final Safety
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Analysis Report (UFSAR) design requirements, was above the upper limits values per ASME Section XI.
The differential pressure data
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was obtained using installed instrumentation (pump discharge pressu,re and suction pressure).
As part of the licensee investigation, it was Setermined that the cooling wrter flow to she pump's lube oil cocier was only 12 gnm tice the required 25 gpm.
The flow for the cooler is providtd from the
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AFW pump discharge.
Scale deposits were found on the cooling water line chect valves.
The valves were cleaned and neemt1 flow restored, f
During the seventh refueling outage, flow testing of the AFW Pump 3A was perfermed using both 1* stalled and test instrumentation.
Evalua-t tion of the ter.t data from the installed instrumentation again indi-cated that :he pump's differential pressure was abnve the limits of ASME Section XI and satisfied the UFSAR design requirements for pump heap. Kowever, the es 41uation of data f rom the tett instrumentation indicated that the pumps diff arertial pressure was belaw the lower ASM5 limits and that the pump's head was below IIFSAR design require-
ments.
Both the installed and the test instrumentation sere verified
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to be properly calibrated.
The licensee concluded, based on pump motor current, that the installed instrumentation was indicating closer to actual conditions and as permitted by ASME Section XI raised the upper allowable limits.
However, no evaluation was performed to determine why the more accurate test instruments were indicating approximately 40 psig less than the installed instruments.
This item remains open until the difference between the installed and test instruments is satis-factorily resolve f
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3.4 (0 pen) Unresolved Item (50-334/87-13-01) Licensee to address cable qualification and corrective actions for annunciator panel flood
event.
In September 1987, rainwater entered a Unit I annunciator panel from outside the plant via an underground cable run resulting in a number of control room alarms.
The conduit involved contained safety related cabling.
L The licensee conducted an investigation and found several manholes
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partially filled with rainwater.
The design of the cable trenches was such that rainwater collecting in manholes at high elevations (switchyard) would flow downhill via cable conduit into the next lower manhole.
This manhole would partially fill, then the water would flow into the next lower manhole until the water eventually flowed into the annunciator panel.
The licensee removed the water from all the affected manhole; and thra the.T.anholes were sealed.
The area around some manholes was built up to prever:t rainwater from collect 1 rig at the top of the man-hole.
All the manholes were subsequently ir.spected and were found firy.
The licensee has implemented procroures that require the retealing of manholes when reopened in the future.
The licensee was not able to determine how long the t4f fected crables we re submerged in water.
The licensee stated the cables involved i
wcre qualified for short term (14 days) submergence.
The inspector questioned whether +.here had been any degrodation of the affected cable insulation which may have occurred as a result of this event.
The licensee stated tbt.t no tasting had been performed outside from routi'te preve;itive meintenance tests where a percentage of those i
li.ies serving load, greater than 100 hp were te.ted during refueling outages.
No contrci power or instrument power lines had been tested.
'This itera remains open pending further assurance that no cable degradation has occurred.
4.
Operational Safety 4.1 General Tours of the following plant areas were conducted during both day and night shifts with respect to Technicsl Specification (TS) compliance, housekeeping and cleanliness, fira protection, radiation control, physical security / plant protection, and operational / maintenance administrative controls.
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-- Control Room
-- Safeguard Areas
-- Auxiliary Building
-- Service Butiding
-- Switchgear Area
-- Diesel Generator Buildings
-- Access Control Points
-- Containment penetration Areas
-- Protected Area Fence Line -- Yard Area
-- Turbine Building
-- Intake Structure
-- Reactor Containment
-- Spent Fuel Building No concerns were identified.
4.2 ESF Walkdown The operability of selected engineered safety feature systems was verified by performing detailed walkdowns of the accessible portions of the systems. The inspectors confirmed that system r.omponents were-in the required alignments, instrumentation was valved in with appro-priate ca'libration dates, as-built prints reflected the as-installed systees and the overall conditions observed were s&tisfactory.
The systems inspected during this period include Emergency Diesel Gener-stor, Safety Injection, Auxiliary Feed Water, ard Recirculation Spray systems. No concerns were identified.
4.3 Operatiors During the course of the inspection, discussions were conducted with operators concerning knowledge of recent changes 'to procedures, facility configuration and plant conditions. During plant tours, lags and records wt:re reviewed to determine if entries were properly made,
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and that equipment status /deficiencias were identified i.nd communt-I cated. These records included operating logs, turnover sheets, tag-out sad jumper logs, process computer printouts, unit off-normal and draft incident reports. The inspector verified adherence to approved procedures for ongoing activities observed.
Shift turnovers were witnessed and staffing requirements confirmed. Inspector comments or questions resulting from these reviews were resolved by licensee per-sonnel.
The inspector attended onsite Safety Review Committee meetings to evaluate the licensee's self-assessment capability.
In addition, inspections were conducted during backshif ts and weekends on 1/04, 1/14, 1/15, 1/19, 1/23, 1/27, and 2/3.
4.3.1 Unit 2 Steam Generator Blowdown Isolation On January 7,1990, while Unit 2 was operating at 85%
power, an automatic isolation of the Steam Generator Blow-down (SGBD) system occurred due to high radiation levels sensed in the blowdown sample line radiation monitor. The
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1 solation was an Engineered Safety Features actuation.
Main condenser air ejector radiation levels remained nor-mal.
The plant operators responded to the event as
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required by procedure and the SGBD system was returned to l
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The apparent cause of the automatic isolation was residual radioactive crud particles, remaining from a prior steam generator tube leak that had broken free and entered the SGBD system.
Three days prior to the event blowdown flow was increased 40 gpm above normal. The licensee postulated i
that this caused the reikase of the crud particles.
Two similar events occurred in August and October 1989, f
when the SGBD system automatically isolated due to the high
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radiation levels (See IR 50-334/89-13; 50-412/89-14 and IR
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50-334/89-22; 50-412/89-21). Both of these events occurred almost immediately after normal blowdown flow nad been
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To prevent recurrence, the licensee increased the alarm setpoint of the SGBD sample line radiation monitor after
performing an evaluation that indicated that the increased
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wtpoint would not exceed the design basis for offsite
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releases. The inspector reviewed the evaluation and found it satisfactory.
The inspector had no further questions.
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4.3.2 Unit ] High bnidentified Leakage l'.
On January 8,1990, a Unit I controlled shutdown from 100%
power was commenced following the determination of uniden-tified Reactor Coolant System leakage (1.45 gpm) in excess
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of Technical Specification requirements (1 gpm). While the shutdown was in p rog re s t,,
olant operaters isolated the source of the leak and the shutdown was terminated with
reactor power at 68%.
The source of the leak was a cracked weld where the instru" ment sensing line for the "A" Reactor Coolant Pump No. 1 i
seal differential pressure transmitter was joined to the transmitter isolation valve.
The isolation valve was shut
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to stop the leak.
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The licensee, in consultation with the pump vendor, per-formed a 10 CFR 50.59 evaluation to verify that there were no safety implications associated with operating with the differential pressure transmitter isolated. The differen-tial pressure transmitter provided no safety functions and was used for indication only.
Pump seal water flow is the parameter which provides alarms indicating seal degrada-tion. Therefore, Unit I returned to full power operation.
No deficiencies were identifie s
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4.3.3
, Unit 1 Shutdown Due to Vital Bus Inverter Inoperability o
On January 19, 1990, a Unit 1 controlled shutdown was performed due to an inoperable 120 VAC vital bus required i
by Technical Specification (TS). The licensee had intended to shut down the unit later the same day to repair a leaking charging header relief valve which had been determined to I
be the source of high (approximately 5 gpm) identified Reactor Coolant System leakage.
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Unit 1 TS 3.8.2.1 required the unit to be shutdown if an inoperable 120 VAC vital bus cannot be returned to service within eight hours.
Unit I had been operating since January 14, 1990, with the No. 3 Uninterruptible Power Sup-ply (UPS) out of service due to a blown fuso.
The No. 3 120 VAC vital bus was being energized from an alternate sour,:e (480V/120V bus).
The licensee had taken the position that a 120 VAC vital bus could be considered oper-
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able when energized from the alternate source.
Following i
discussions with the inspectar and NRC Region I staf f, the licensee committed to shutdown Unit 1 if the No. 3 U.0S could not be immediately returned to service.
The No. 3 UPS requit ed some minor adjustments and could not f.e imed-tafely returned to serv ce, therefore a r.onrrolled shutdown i
was initiated.
The No. I UPS was ro t.v ened to service
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approximstely four hours later.
On January 21, 1990, Unit I returned to power operation following the re.placeuer.t of the leaking header relief valve (loceted at th in'tet to the Chemical and Volume Con-trol System Reger erative Heat hcMnger) and soce other
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minor repairs.
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A rpecial inspection of this event was concucted buween
January 22-26, 1990.
For details see IR 50-334/90-04.
4.4
, tant Security / Physical Protection i
Implementation of the Physical Security Plan was observed in various plant areas with regard to the following:
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Protected Area and Vital Area barriers were well maintained and
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not compromised; Isolation zones were clear;
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Personnel and vehicles entering and packages being delivered to
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the Protected Area were properly searched and access control was s
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a in accordance with approved licensee procedures; Persons granted access to the site were badged to indicate i
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whether they have unescorted access or escorted authorization; Security access controls to Vital Areas were being maintained
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and persons in Vital Areas were properly authorized;
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Security posts were adequately staffed and equipped, security
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personnel were alert and knowledgeable regarding position i
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requirements, and that written procedures were available; and Adequate illumination was mai+tained.
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No deficiencies were identified.
4.5 Radiologic &1Centrols rj.
posting and c'>ntrol of raoiatior, and high radis11on t.reas were inspected.
Radiation Work Pamit compliance and use of personnel monitein:) devices were checked. Ocnditions of stco-of f pads, dis-poral of protective clotMng, radiation cor. trol job coverage, area
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monitor operability and calibration (portable. and permanent) and per-sonnel frisking were observed on a sampling basis.
On February 12, 1990, while conducting a tour of tt e Unit 1 Safe-guards Buf1 ding, a radiologically controlled area, the inspector identf fied a raaiation technician (RT) who appeared to be sleeping.
At the time, two workers were engaged in decontamination activities
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in a posted contaminated area to which the RT was assigned to inter-rrittently monitor.
Tho RT subsequently admitted that he had " dozed off".
The radiation levels in the arca were less than one mrem /hr.
The radiation work permit for the decontamination activity specified which steps required continuous RT coverage.
At the time of the incident, continuous RT coverage was not required.
The licensee terminated the technician's employment.
4.6 Plant Housekeeping and Fire Protection Plant housekeeping conditions, including general cleanliness condi-
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tions and control and storage of flammable material and other poten-
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tial safety hazards, were observed in various areas during plant L
tours.
Maintenance of fire barriers, fire barrier penetrations and l
verification of posted fire watches in these areas were also observed.
The inspector conducted detailed walkdowns of the access-i; ible areas, including normally locked high radiation areas, of both L
Unit 1 and Unit 2.
No significant deficiencies were identified.
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Weaknesses in housekeeping were noted in the Unit 1 Safeguards and Auxillary buildings. Excessive dirt and debris (tape, rags, paper trash, cotton glove liners, etc.) were observed in many areas.
In some potentially contaminated work areas, the inspector observed excessive dirt and debris, which could potentially result in person-nel contamination outside the posted contaminated areas.
In addi-tion, the inspector identified unrestrained carts and ladders in the vicinity of safety related equipment. These items were corrected by the licensee by the end of the period. General housekeeping in Unit 2 was good.
5.
Surveillance Testino The inspectors witnessed / reviewed selected surveillance tests to determine whether properly approved procedures were in use, details tere adecuate, test instrumentation was properly calibrated and used, Technical Specifi-Lations were satisfied, testing was performed by qualified personnel and tr.t results satisfied acceptance criteria or were properly dispositioned.
The following Turve111ance testing activities were reviewed:
CST 1.33.3 Weekly Diesel Engine Drive 'fre Pump Operation Test.
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OST 2.36.2 En<ergency Oiesel Generstar (2EGS*EG2-2) Monthly Test.
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OST E.24,3 Motor Driven Auxiliary Feed Pump (2FWE*P238) Test.
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OST 2.24.4 Steam Driven Auxiliary Feed Pump (2 FVE^ P24) Test
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(observed twice during period).
No deficiencies were identified.
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Mrintenance The inspector reviewed selected maintenance activities to assure that:
the activity did not violate Technical Specification Limiting Condi-
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tions for Operation and that redundant components were operable; required approvals and releases had been obtained prior to commencing
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work; procedures used for the task were adequate and work was within the
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skills of the trade; l
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activities were accomplished by qualified personnel;
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where necessary, radiological and fire preventive controls were ade-
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quate and implemented; QC hold points were established where required and observed; and,
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equipment was properly tested and returned to service, j
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Maintenance activities reviewed included:
MWR 907608 A Main Feedwater Regulating Valve
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MWR 9G7609 B Main Fire 6/ater Regulating Valve
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MWR 907610 C Main Feedwater Regulating Valve
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PMP-2-39-BYS-BAT-Cr1G 3E Clean and Inspect No. 2 Battery Charger
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2-75-HOTOR-15E Insrect, Test, and Lubricate Quenen Spray Pump 21A
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4RVS*2AF-2Ei Inspect and Test Quench Spray Pvwp 21A Circuit Breater
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51-VE 202 Quench Spray Pump 21A Relay Test
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50-VE-202G Quench Spray Pump 21 Relay Test
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MWR 93007)
Repriir No. 3 Vital Bus Inverter
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PMP-1-38-ZB-UPS-2-4-31 No. 3 Uninterruptible Power Supply
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Preventive Maintenance
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No deficiencies were identified.
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Unit 2 Mtssed Post Maintenance Test On February 12, 1990, the licensee determined during a maintenance review, that a steam generator pressure transmitter which provided an input to the
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Solid State Protection System (SSPS) had not been response time tested as
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required by Technical Specifications.
Following this determination, the affected SSPS channel was declared inoperable and tripped in accordance with TS.
Unit 2 TS 4.3.2.1.3 requires that the response time of each Engineered Safety Feature function be demonstrated to be within limits at least once each 18 month..
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On January 17, 1990, Channel III "B" Steam Generator Pressure Transmitter (2 MSS-PT485) failed downscale. The transmitter was subsequently replaced and calibrated; however time response testing was not performed.
The transmittar provides an input signal to actuate safety injection and steam line isolation protection functions on low steam line pressure.
The apparent cause of the missed surveillance was an inadequate post-
maintenance test procedure. The site administrative procedure "The Main-l tenance Work Request" contains a matrix of post-maintenance test recommen-
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dations for various plant components including pressure transmitters, i
This matrix was utilized when planning the replacement of the above pressure transmitter.
The matrix did not include requirements for time response testing and therefore time response testing was not added to the Maintenance Work Request as required.
Prior to the event, the licensee had draf ted a new post-maintenance test
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matrix which included time response testing recommendations. However the draft had not yet been approved.
As an interim corrective measure, Instrumentation and Control Maintenance planners were instructed to verify whether time response testhg was required for all maintenance on systems that require such testing by TS.
A review was conducted to determine if other instrumentation was not time respnnse tested as t equired. None were identified.
The transmitter was satisfac'.oiily tested on February 13, was found well within the recyired time limit, and was returr,ed to service.
The inspector concluded the failure to perform the required time response testirc was of minor safety significance (Severity Level TV). The licen-
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see informed the inspector that the incident will be formally re the NRC via a Licensee Event Report as required.
The lleensee' ported to s correc-tive actions and investigation of the incident were thorough and tinely.
In addition, there were no past similar occurrences identified.
There-fore, the failure te meet the requirements of Technical Specification 4.3.2.1.3 is not being cited because the criteria specified in Section V.G of the Enforcement Policy were met (Non-cited Violation NRV 50-412/
90-02-01).
8.
Unit 1 Recirculation Sora4 eat Exchanger River Water Radiation Sample H
Line Design problem On January 10, 1990, the licensee informed the NRC that the Recirculation Spray Heat Exchanger (RSHX) river water radiation monitor sample lines did not meet the requirements of 20CFR50, Appendix A, General Design Criterion (GDC) 57, " Closed System Isolation Valves," and no exception had been pre-viously taken in the Updated Safety Analysis Report. GDC 57 requires that
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Il for each line that penetrates primary reactor containment and is neither
part of the reactor coolant pressure boundary nor connected directly to the containment atmosphere must have at least one containment isolation valve which must be either automatic, locked closed, or capable of remote manual operation.
This condition was discovered during an engineering design review, i
The Recirculation Spray System is designed to provide for containment cooling and depressurization following a Loss of Coolant Accident. The River Water System supplies cooling water to the four RSHXs. During acci-dent conditions, the river water effluent is continuously monitored to detect RSHX tube leakage. On each river water return header, a one inch branch line supplies the radiation monitors.
These branch lines are located between the contair. ment cutside wall and each RSHX river water effluent isolation valve.
The branch lines are isolable by only a local manual valve.
The licensee prepared a Astifichtion for Continuad Operation (JCO) which was reviewed by the NRC.
The JC0 stated that the existing design pre-
sented no euverse effects as a result of postuletsd accidents since the flow of enntaminatea fluid through the branch sample line would require a passive failure be assumed (RSHX tube leat) in the short term following an
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accident.
The Unit 1 licensing basis does not requirt postulating such failures. In the loag term, there were also no adverse affects since by procedure the Recirculation Spray Pumps would be shutdown and the contain-ment would be at subatmospheric pressure, thm removing the driving force for the tuce loak.
The JC0 fs ther stated that as conipenatory measures, operating procecures r
were in place that direct operators to isolate the affected RSHX and its associated radiation monitor in the event of a tube leak.
In tddition,
the JC0 stated that RSHX tube integrity was periodically monitored by
pressure and Freon gas testing as well as eddy current testing.
The inspector verified the licensee compensatory measures and found the measures to be adequate. During the last refueling outage, the RSHX were tested using the above tests.
Eddy current testing had revealed degrada-tion of a number of RSHX tubes which were subsequently replaced (see IR 89-334/89-22; 50-412/89-21).
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The licensee submitted a request for an exemption to GDC 57. This issue is Unresolved pending the. approval of the cxemption or completion of any required modification (50-334/90-02-01).
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9.
Fitness for Duty The license's Fitness for Duty training program was reviewed to verf fy whether required training wts being conducted to implement the Fitness for
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Duty requirements of 10 CFR 26.
The inspector attended a training class given to nonsupervisory personnel.
Included in this training were requirements for personnel providing protected area escort duties.
The licensee provided no formal training classes to supervi sory personnel.
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Supervisors were given a self-study course with an open reference exam.
The inspector reviewed all the course material and found it to be adequate to implement the Fitness for Duty program.
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10.
Inoffice Review of Licensee Event Reports (LERs)
The inspector reviewed LERs submitted to the NRC Region I Office to verify that the details of the event were clearly reported, including accuracy of the description of cause and adequacy of corr 1ctive action. The inspector determined whether further 10 formation was required from the licensee, whether generic imp.ications were indicsted and whether the ever.t war-ranted onsite foliewup.
The following LERs were reviewed-Unit 1;
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tEF 89-13-00 Diesel Gener.* tor Autostart on bus Under v'oltage.
LER 89 15-00 Inadvertent Safety Irjection During Restoration of Solid State Protectior; Systera.
LER 89-16-00 Feedwater Isolation Due to Erratic Steam Generator Levei Transmitter.
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LER 89-17-00 Feedwater isolation Due to Erroneous i.evel Transmitter Rcot
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Vaive Position.
LER 89-18-00 Reactor Trip Due to Loss of Feeder Breaker Supplying Con-trol Rod Drive Motor Generator Set.
LER 90-01-00 Reactor Coolant Leakage in Excess of Technical Specifica-tions.
LER 90-03-00 Condition Outside the Design Basis for the Recirculation Spray System.
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i Unit 2:
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LER 90-01-00 Engineered Safety Feature Actuation - Steam Generator Blow-down Isolation.
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L The above LERs were reviewed with respect to the requirements of 10 CFR
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i-50.73 and the guidance provided in NUREG 1022. Generally, the LERs were
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found to be of high quality with good documentation of event analyses,
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root'cause determinations and corrective actions.
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.t 11. Unresolved Items-l t
Unresolved items are matters about which more information is required in order to ascertain whether they are acceptable items, violations or devia-I tions.. One unresolved items was identified in this inspection (see i
Section 8).
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12.
Meetings i
Periedic meetings were held with senior facility manageme;,t during the
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ccurse of this inspection to' discuss the inspection scope and findings. A
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summary of inspection findings was further discussed with the licensee at t
the conclusion of the report period on February 28, 1990.
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