IR 05000338/1990023
| ML20058A855 | |
| Person / Time | |
|---|---|
| Site: | North Anna  |
| Issue date: | 10/09/1990 |
| From: | Fredrickson P, King L, Lesser M NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION II) |
| To: | |
| Shared Package | |
| ML20058A852 | List: |
| References | |
| 50-338-90-23, 50-339-90-23, NUDOCS 9010290251 | |
| Download: ML20058A855 (13) | |
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.jsisto UNITED STAT E3.
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q'o NUCLEAR REGULATORY COMMISSION
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REolON 11, p
. g-y 101 MARIETTA STREET,N.W.
- I e ATLANT A, GEORGI A 303E
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Report Nos.: '50-338/90-23 and 50-339/90-23 Licensee: Virginia Electric & Power Company
5000 Dominion Boulevard Glen Allen, VA 23060 i
i Docket Nos.: 50-338 and 50-339 License Nos.:
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L Facility Name: North Anna 1 and 2
. Inspection Conducted: August 19 - September 15, 1990 Inspectors:
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M.S. LtSpj( Senior ~ Resident Inspector Date 54gned
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h0W/ &
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c 3.P. Kin g$1 dent Inspector D&t( Signed i
Approved by:
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P.E. Fredrickson, Section Chief Date 5fgned c
Division of Reactor Projects I
SUMMARY I
i Scope:
.This routine inspection by the resident-inspectors involved the following
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operations, maintenance, surveillances, operational event followup,
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licensee'. event report followup, evaluation of licensee'self-assessment, and
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- action, on ' previous inspection findings.
Inspections of licensee backshif t
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- activities were conducted on the following days:
August 19, 27, 28, 29, 30,
- 31, and September 2, 3, 5, 6, 7.
? esults.
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d1 Within the areas inspected,. one non-cited violation involving an unlocked high j
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' radiation area door was identified (parag aph 3.d).
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r Operator response to an uncontrolled loss in reactor vessel level was good and
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' averted' a potentially more serious problem -(paragraph 3.a).-
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9010290251 901009 ADOCK 050 338 gDR
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The licensee has identified an increasing trend of mispositioned valve events on which, although each event was not safety significant, increased attention is warranted (paragraph 3.b).
A management decision was made to shutdown Unit 2 on August 21, 1990, and comence the planned refueling outage early when primary to secondary tube leakage increased.
The decision was a prudent and conservative action considering Technical Specifications would have allowed operations with a larger leakage rate (paragraph 3.c).
A strength was identified with the effective use of the plant simulator to conduct training for major surveillance tests (paragraph 5.a).
The licensee has determined that many of the pressurt'zer heater cables are undersized and this has contributed to numerous events where heaters were lost due to tripped circuit breakers or blown fuses. Recovery of pressure w:s delayed following a reactor trip in June,1989, due to the loss of saveral heaters. While a corrective action plan is proposed, it is beino delayed until 1992(paragraph 4.a.).
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The quality of the daily plant status report generated by the STA continues to beastrength(paragraph 6b).
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e-l REPORT DETAILS l-i L
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Persons Contacted Licensee Employees
- M. Bowling, Assistant Station Manager L. Edmonds, Superintendent, Nuclear Training
- R. Enfinger, Assistant Station Manager
- M. Gettler, Superintendent, Site Services
- D. Hencock, Superintendent, Engineering
- G. Kane, Station Manager P. Kemp, Supervisor, Licensing
- W. Matthews, Superintendent, Maintenance D. Roberts, Supervisor, Nuclear Safety Engineering
- R. Shears, Superintendent, Outage Management
- J. Smith, Manager, Quality Assurance
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- A. Stafford, Superintencent, Health Physics
- J. Stall, Superintendent, Operations
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Other licensee employees contacted included engineers, technicians. operators, mechanics, security - force members, and office personnel.
NRC Resident Inspectors
- L. King, Resident Inspector
- M. Lesser, Senior Resident inspector
~ Attended exit interview
Acronyms and initialisms used throughout this report are listed in the last paragraph.
2.
Plant Status Unit 1 operated the entire inspection period at 100 percent power. At the end of the period, the unit had been on-line for 234 days.
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-Unit 2-started the inspection period at 50% power, in coastdown for a scheduled refueling outage-starting September.7. On August-20 primary to secondary _ leakage from the B SG increased to approximately 38 gpd.
The licensee reduced power to 30% as a conservative measure.
On August 21
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management made a decision to shutdown the unit and commence the refueling outage on the basis that operation at 30% for an extended time.was not economical. The unit was shutdown and entered mode 3 The unit operated
" breaker to breaker" and set a world record for Westinghouse pressurized
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light v:ter reactors at 469 continuous days on-line.
The unit entered mode 6 on September-4.
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3.
Operational Safety Verification (71707)
The inspectors conducted frequent visits to the control room to verify proper staffing, operator att9ntiveness and adherence to approved procedures.
The inspectors attended plant status meetings and reviewed operator logs on a daily basis to verify operational safety and compliance with TS and to maintain awareness of the overall operation of the facility.
Instrumentation and ECCS lineups were periodically reviewed
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from control room indications to assess operability.
Frequent plant tours were conducted to observe equipment status, fire protection programs,
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radiological work practices, plant security programs and housekeeping.
Deviation reports were reviewed to assure that potential safety concerns were properly addressed and reported.
Selected reports were followed to ensure that appropriate management attention and corrective action was applied, l
a.
Reactor Vessel Head Void Due to Air Intrusion
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On August 29,1990, at 0045 hours5.208333e-4 days <br />0.0125 hours <br />7.440476e-5 weeks <br />1.71225e-5 months <br /> with Unit 2 in cold shutdown, the control room operator noticed pressurizer level trending up from eight percent coincident with a decreasing trend in indicated reactor vessel level from 100 percent. An operator was imediately dispatched to the containment building to vent the reactor vessel head.
In-the interim the operator contacted the personnel responsible for -
containment isolation valve Type C leakage testing. The Type C crew
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informed the operator that they had just started attempting to
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pressurize the hot leg safety injection lines with air.
Air was being admitted to perform a leak test on the alternate charging header to SI hot leg injection line check valve.
The test crew was J
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l directed to imediately stop pressurizing and vent the header. After
venting the header at 0100 hours0.00116 days <br />0.0278 hours <br />1.653439e-4 weeks <br />3.805e-5 months <br />, pressurizer level stabilized at 30 percent and reactor vessel level stabilized at 84 percent.
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level corresponds to a level just above the top of the reactor vessel head flange.
Reactor vessel head venting was secured at 0200 hours0.00231 days <br />0.0556 hours <br />3.306878e-4 weeks <br />7.61e-5 months <br />
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-with reactor vessel level back at 100 perce,nt and pressurizer level
at 8 percent.
L The Type C test crew was attempting to pressurize the SI hot leg injection header to 45 psig.
The. test boundaries included the L
containment isolation check valve and the individual hot leg SI line l
throttle valves. Although this check valve had been tested many times l
in previous outages-using these boundaries, the RCS conditions that L
existed for this~ test had never existed for previous tests, h
Specifically, in previous tests either RCS pressure was greater than 45 psig or the reactor head was removed with the refueling cavity flooded.
In previous outages. this penetration and the normal charging header to SI hot ' leg' injection penetration were usually tested concurrently.
Since this ' approach required isolation of both l
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i charging headers, the test was performed with the unit defueled so boration flowpath requirements would be met, in the current outage, these penetrations were scheduled to be tested separately 50 as-found
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leakages could be determined early in the outa Since the excessive leakby of the Si line throttle valve (ge.s) had not been r
previously identified, their use as - test t9undary valves was not considered to be a problem.
For this test, the reactor vessel head was still in place and the RCS was at 20 psig.
When air leaked by the throttle valves (s) it accumulated in the reactor head and began i
to displace RCS inventory up into the pressurizer. Swift recognition and immediate actions by the operators terminated the event.
A calculation was performed by the licensee to detemine the maximum
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possible size of the reactor head void for this event.
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detemined that 2500 gallons would have been displaced into the pressurizer.
The associated reactor head void size would not have resulted in total voiding of the head region. Reactor vessel water
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j level would have remained in the vessel flange region.
This is 36 inches above the level where reduced inventory conditions apply. The
ability to remove decay heat would not have been jeopardized in the
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unlikely event of undetected continuous air injection.
b.
Mislabeled Valves On September 12, 1990, with Unit 2 in Mode 6, operators attempted to flow test the boration flowpath through the normal charging header by gravity draining from the RWST.
The operator noticed an increasing g
l containment sump level and identified the. source of leakage to be a normally closed drain valve (2-CH-337) on the charging header which was open.- The operators secured the evolution and a minimum amount of water was lost. It was later identified that the valve was labelled incorrectly as a drain valve on the letdown line (2-CH-384).
The' letdown line was isolated land drained the day before which explained how 2-CH-337 was opened.
Technical Specifications require this flowpath to be operable while in Mode 6.
The licensee was able to show through calculations that the boration flowpath was not rendered inoperable due to this drain valve being open.- The licensee has recently identified several examples of valves in various systems being found out of position.
One' drain valve left open during chemical addition to a steam generator resulted in a spill of 100 gallons of condensate.
A second valve left open during steam generator pressurization for tube leak checks resulted in several water treatment valve failures. While each event
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in itself was not safety significant, the licensee is closely trending and monitoring performance, c.
Unit 2 SG Primary to Secondary Leak The licensee had been closely monitoring primary to secondary leskage from the B SG.
On August 20, 1990,' with the unit operating at SO
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l percent power, air ejector alarms and main steam line
l N-16 alarms alerted operators of increased leakage.
Various indicators trended the leakage from 21 gpd to 38 gpd in about 11/2 hours. Management ordered a power reduction te 30 percent power and upon reaching this level, the leakage decreased to 6 gpd. TS allows operation with leckage up to 500 gpd.
The unit had been in coastdown with a refueling outage scheduled to consnence September 7.
Although the unit was eight days from reaching the world andurance record for light water reactors, management decided to shutdown the unit and commence the refueling outage on the basis that operation at 30 percent power for an extended duration was not economical.
This decision was considered conservative and indicative of the licensee's consnitment towards nuclear safety.
The inspectors observed portions of the shutdown and cooldown and verified that cooldown rates were within limits, d.
Unlocked High Radiation Area On September 4,1990, the Unit 2 refueling cavity access ladder was found unlocked and unattended.
The ladder is the only access to the cavity which is a high radiation area and to the transfer canal which is an extreme high radiation area.
The licensee determined the ladder was left open for approximately one hour following the-failure of the reactor head detensioning crew and health physics technicians to lock it upon exiting.
The licensee determined there were no unauthorized entrances made to the area during this time, however, they did identify training weaknesses associated with high radiation area key turnover.
Technical Specification 6.12.2 requires this area to be locked.
This licensee identified violation is not ~
being cited because criteria specified in Section V.G.1 of the NRC Enforce.nent Policy were satisfied. This is identified as NCV 339/90-23-01: Unlocked High Radiation Area.
e.
SG Tube Plug Inspections The licensee has identified several wet or boron caked steam generator plugs when inspected from the primary side.
This is indicative of leaking plugs. The examples include both the explosive and mechanical type plugs in both the hot and cold legs.
The explosive plugs were installed in row one tubes prior to the SG being placed in service and the licensee used flow slot photograph
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techniques to observe for. bulging and justify continued op% tion.
The licensee's plans are to drill out and replace the mechanical plugs. A sample of plugs are being eddy current tested to identify possible primary water stress corrosion cracking or-plug scaling problems on the hot leg.
Cold leg plugs are being evaluated icr degraded plugs or further explanations as to the source-of borated water.
One noncited violation was identifie.
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4.
MaintenanceObservation(62703)
Station maintenance activities were observed / reviewed to ascertain that the activities were conducted in accordance with approved procedures, regulatory guides and industry codes or standards, and in conformance with TS requirements, a.
Press,rizer Heater Reliability The 1xensee has continued to experience actuations of p)ressurizer heater protective devices (i.e., fuses, circuit breakers. Previous concerns were identified in Unresolved Item 338/89-26-03, where pressurizar p" essure recovery following a reactor trip was delayed due to s-Ix pressurizer heaters lost when their breakers tripped.
Concerns were also iised with the use of portable fans to cool the rooms where breaker and fuses are located.
The inspectors reviewed an engineering evaluation which failed to address the effects on heater operability if the fans were lost. Recent events included the l
loss of some heaters on August 4 and August 28 during routine operation at power.
The inspectors requested that deviation reports be trended for similar events, which revealed 13 circuit breaker trip events and 28 blown fuses. The problems can be traced back to as far
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as 1987.
A major factor causing the protective device actuations is overheating of the equipment (i.e., cabling, fuses). Much of the cabling outside containment is excessively packed in conduit and resistance heat is not effectively dissipated.
This has caused insulation deterioration over the years to a point where the cables must be derated.
Licensee calculations to determine the ampacity of heater power cables applied derating factors to account for ambient temperature conditions and concluded that most of the cables outside containment are undersized.= Some Unit 2 cables inside containment are also undersized.
Another problem appears to be related to excessive. ambient temperatures in the area of the pressurizer heater circuit breakers and fuse panels. Recorded temperatures have been as high as 39 degrees C on Unit I and 40 degrees C on Unit 2.
The Unit 1 circuit breakers are rated at 40 degrees C.
The fuses on both units are rated to.30 degrees C.
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A third concern is heater use while at power. The licensee routinely operates with.the backup heaters energized which is not consistent with the intent of the design.
The continuous load contributes to the excessive heating.
The licensee' is currently evaluating operation with only the proportional heaters energized.
However, the licensee is concerned about the adverse effects associated with. pressurizer surge line thermal stratification,.
pressurizer boron stratification and leaking spray valves.
The licensee has proposed several modifications to remedy the situation including-cable replacement, fuse cabinet ventilation upgrades, breaker and fuse upgrades, increased preventive maintenance and cable separation. The inspectors determined that very little corrective l
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action is planned for the current Unit 2 outage.
The licensee cleaned the fuse panels which resulted in increased resistance to ground readings.
It is believed, bewever, that this will not contribute significantly towards improved performance.
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inspectors also determined that cable replacement has been deferred on Unit I until December,1992 and on Unit 2 until June,1992. The inspectors discussed concerns regarding delaying the corrective action with licensee management.
The licensee postponed the cable replacement due to engineering constraints. Technical Specifications require the pressurizer be operable with at least 125 kilowatts of heaters.
The inspectors remat.ed concerned as to whether this would be available during a worse case scenario and the present capacity problems; and requested the licensee to evaluate the heaters for operability.
Continued inspection will be conducted under the aforementioned unresolved item, b.
Fouling of Charging Pump Seal Coolers From Service Water The licensee removed the IB charging pump from service in order-to inspect and repair a leaking mechanical seal.
The licensee discovered the rubber seal bellows was damaged due to overheating.
Further inspection identified that-the shell side of the seal cooler, which is cooled by service water, wrs significantly fouled with mud and most likely the cause of the tailure of the bellows.
The licensee inspected all the other seal coolers on a priority basis and discovered they were also fouled.
The inspectors determined that the seal coolers were not included in a preventive maintenance program nor adequately trended. Discussion with the licensee determined that historical problems such as high bearing temperatures or failed seals, had not been experienced. The licensee had -been in the process of reviewing requirements in response to Generic Letter 89-13, Service Water System Problems Affecting Safety Related Equipment.
The inspectors reviewed the licensee's initial response dated January 29, 1990, which states that inspection and maintenance programs to-remove excess. accumulations will be developed prior to restart from the next refueling outage which is in November, 1990.
No violations or deviations were identified.
5.
SurveillanceObservation(61726)
The inspectors observed / reviewed TS required testing and verified that-testing was performed in accordance with adequate procedures, that test -
instrumentation was calibrated, that LCOs were met and that any deficien-cies identified 'were properly reviewed and resolved.
The following
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surveillances were either observed or reviewed:
2 PT-213.8 Safety injection Valve Inservice Inspection 2-PT-57.4 Safety injection Functional Test
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2-PT-66.3 CDA Functional Test 2-PT-62.3 Equipment Hatch Escape Lock Door Seal Testing a.
CDA and SI Functional Tests Part of the preparation for the SI and CDA functional testing included classroom and plant simulator training.
The training ensured test personnel were familiar with the test procedure, control room layout and plant response. This training proved to be effective as the tests were completed with only minor problems, b.
Insulated Support inspections The-licensee's QA identified that visual examination of component supports covered by insulation has not been performed in accordance with ASME Code IWA-2210.
It appears that the licensee misinterpreted
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guidance not to remove insulation, as allowed by IWF-1300(e), to include non-load bearing supports.
IWF-1300(e) allows the support boundary to extend from the surface of the component insulation, provided the support either carries the weight of the component or serves as a structural restraint in compression.
The licensee is appropriately proceeding to conduct the inspections.
No violations or deviations were identified.
6.
Evaluation of Licensee Self Assessment Capability (40500)
a.
QA Review of Maintenance Program The inspector reviewed the recent QA >erformance evaluation of station maintenance activities. T1e evaluation was conducted with the use of inspection modules and included review of maintenance planning, testing procedures, procurement, tools, craft training and qualification, in addition to observed activities over a ten-month period. The evaluation was considered comprehensive.and effective by the. inspectors.
Several strengths and weaknesses were identified by the evaluation.
Strengths included: maintenance of good equipment material condition and station housekeeping, work order tracing
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systems, work order backlog reduction, personnel training and calibration programs. Weaknesses included lack of documentation of completed work causing examples of confusinn following crew turnover, lack of work scope walkdowns by planning, lack of references to correct procedures, inadequacies with vendor manuals, weak post-maintenance tests or acceptance criteria and weak proce-dures (those which have not been upgraded). The inspectors concluded that management is aware of the weaknesses in the maintenance program and is taking steps to improve long term performance, b.
Station Nuclear Safety The inspectors reviewed aspects of the licensee's independent onsite review group, Station Nuclear Safety.
SNS duties include trending of deviation reports, maintaining self assessment data, operating experience review, human performance and root cause evalu: tion in addition to the shift technical advisors.
The group appe.ared to be well qualified and adequately staffed and headed by an 3R0 licensed
individual.
The inspectors reviewed a sample of rcot cause evaluations which appeared to be adequate.
The inspectors reviewed STA activities and determined that they were effective in providing independent review of shift activities.
The daily plant' status report, which is produced by the STA for management review, includes a sumary and assessment of significant events. The report continues to be a strength.
The inspectors noted that the STA is not required to complete a shift
turnover sheet and discussed the advantages of a sheet with the supervisor of SNS.
The supervisor determined.that a shift turnover sheet would be beneficial, SNS identified that burned out light bulbs were not being replaced in the control board indication of main steam trip valves. This was due to operations management direction not to replace the bulbs-for fear of inadvertently shutting one of the valves.
SNS identified, however, that' the indication and valve circuitry are isolated and
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that bulb replacement could not result in valve closure.
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inspectors requested that operations review the SNS evaluation.
7.
LERFollowup(92700)
The following LERs were reviewed and closed. The inspector verified that oi reporting requirements had been met, that causes had been identified, that.
corrective actions _ appeared appropriate and that generic applicability had
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been considered..
Additionally, the inspectors confirmed that no
unreviewed-' safety questions were involved and that violations of regulations or TS conditions had been identified.
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(Closed) LER 338/89-03:
Void in Fill Material of Fire Barrier Penetration.
The licensee identified a void in the top of the fill material of a fire barrier penetration while perfonning post-modification
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testing on an adjacent penetration.
The cause of the void was not determined; however, it appeared as though the void resulted when a conduit was removed without proper refilling. Corrective action included refilling the penetration with silicone foam insulation, reviewing
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administrative controls and issuing a memorandum to remind personnel of fire barrier requirements.
L (Closed) LER 338/89-01: Sluggish Operation of ITE 480 Volt Breakers Due to inadequate Lubrication.
The licensee had the vendor representative completely tear down, clean and lubricate the ITE 480 volt breakers for both units.
All breakers were then satisfactorily tested. A program has been developed for tear down and lubrication of the breakers.
(Closed) LER 338/89-04: Steam Generato-Tube Defects.
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reported the placement of its SGs in Category C-3 pursuant to TS 4.4.5.S.c
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due to excessive tube defects.
The cause of the defects is primary water stress corrosion cracking at the tube support plates and certain tubes being susceptible to fatigue from localized flow instabilities. All tubes exhibiting indications were plugged. Tubes susceptible to fatigue failure were plugged with sentinel plugs.
By a Safety Evaluation Report dated
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June 28,1989, the NRC approved restart of Unit 1 on the basis that the
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scope and type of inspections performed on the SG provide reasonable
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assurance that all tubes remaining in-service currently have adequate
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integrity to sustain the full range of normal operating and postulated
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accident loadings.
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(Closed) LER 338/89-05: Reactor Trip Due to Main Feedwater Regulating L
Valve Closure and Subsequent Steam Generator Tube Leak.
The licensee modified the air lines to the feedwater regulating valve as a result' of the failure which caused the valve to close.
The valve trim of the
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feedwater regulating valves was changed which resulted in less vibration.
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(Closed)LER 338/89-07: Local Leak Rate Limit Exceeded. The three service
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water and two component cooling water valves were inspected, adjusted, and retested to within acceptable leak rates prior to the end~of the refueling period.
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Action on Previous Inspection Items (92701, 92702)-
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_ (closed) VIO 338,339/88-31-02:
Failure to Follow Procedures With.12 Examples. The licensee responded to the violation in correspondence dated January 23, 1989,- and April 26. 1989.
The licensee assigned a task team-to conduct a performance based review of procedure adherence and concluded that configuration control weaknesses, procedure weaknesses and personnel error contributed to the violation.
Programmatically inadequate job turnovers and con.nunications caused many procedure adherence problems.
Additionally, understanding and implementation of administrative proce-dures was poor at the working level.
Corrective actions included the E
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initiation and enhancement of several programs such as coaching, check operator, human performance evaluation, self checking and self assessment.
Other actions to imorove performance included the upgrading of the tagging i
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program and enhancements to drawing control.
The inspector determined
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that a recomendation by HPES Report 88-167 to increase available lighting in the piping penetration area of the auxiliary building had not been completed.
The poor lighting contributed to a safety injection flow transmitter equalizing valve mispositioning event. The date originally scheduled to implement the modification (EWR 89-245) was September,1989, however, this was extended to November,1991. Pending completion of the
lighting modification, this is identified as Inspector Followup Item 339/90-23-02: Completion of Modification EWR 89-245 to improve Lighting in Auxiliary Room Penetration Area.
(Closed)IFl 338/89-03-04:
Verify Adequate Service Water Flow Through the Recirculation Spray Heat Exchangers. The system was rebalanced and valves adjusted to provide design flow through the recirculation spray heat exchangers.
(Closed) IFI 338,339/89-03-06:
Correct CAD Drawings and Eliminato Need for Uncontrolled Composite Drawings.
The licensee has corrected the CAD drawings and provided new composite CAD drawings which are controlled.
(Closed) IFl 338,339/89-03-07:
Review Changes to Station Drawing Update Program and Method for Verifying Accuracy of Drawings.
The licensee revised the drawings and additional changes were accomplished by the
. Drawing Update Request Program.
(Closed)V10'338/89-08-01:
Inadequate Maintenance Procedure for 480 Volt ITE Breakers. The licensee revised the maintenance procedure to be more specific as to where and what type of lubricant should be.used.
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breakers were taken apart, cleaned and lubricated by an authorized vendor
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representative.
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'(Closed) URI 338,339/89-22-01:
Determination of Safety Evaluation Concerning a Jumper Installed on a Radiation Monitor. The licensee has revised ADM 14.1 " Jumpers and Temporary Modifications" to include specific requirements to ensure that jumpers installed by an approved procedure are
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maintained operable.
9.
Exit (30703)
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The inspection scope and findings were sumarized on September 19, 1990,
with those persons indicated in paragraph 1.
The inspectors described the areas inspected and discussed in detail the inspection results listed below.
The licensee did not identify as' proprietary any of the material provided. to. or reviewed by the inspectors during this inspection.
Dissenting coments were not received from the licensee.
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Item Number Description and Reference NCY 339/90-23-01 Unlocked High Radiation Area (paragraph 3.d)
IFl 339/90-23/02 Completion of Modification EWR 89-245 to improve Lighting in Auxiliary Room Penetration Area (paragraph 8).
10. Acronyms and initialisms ADM Administrative Manual ASME American Society of Mechanical Engineers
CAD Computer Aided Drafting CDA Containment Depressurization Actuation ECCS Emergency Core Coolant System EWR Engineering Work Requests GPD Gallons Per Day HPES Human Performar,ce Evaluation System IFI Inspector Follow-up Item LCOs Limiting Conditions for Operations LER Licensee Event Report NCV Noncited Violation NRC Nuclear Regulatory Commission PSIG Pounds Per Square Inch Gauge QA Quality Assurance
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RWST Refueling Water Storage Tank l
SG Steam Generator SI Safety Injection l
SNS-Station Nuclear Safety SR0 Senior Reactor Operator STA Shift Technical Advisor TS-Technical Specification
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URI Unresolved Item VIO Violation
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