IR 05000338/1990025
| ML20062H351 | |
| Person / Time | |
|---|---|
| Site: | North Anna  |
| Issue date: | 11/19/1990 |
| From: | Fredrickson P, King L, Lesser M NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION II) |
| To: | |
| Shared Package | |
| ML20062H350 | List: |
| References | |
| 50-338-90-25, 50-339-90-25, NUDOCS 9012040270 | |
| Download: ML20062H351 (15) | |
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UNITE D STATES
[pm Clig o NUCLEAR REGULATORY COMMISSION ;
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101 MARIETT A STRE ET, AT L ANT A, CEoRGI A 30323
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Report Nos.: 50-338/90-25 and 50-339/90-25 l
Licensee: Virginia Electric & Power Company
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5000 Dominion Boulevard i Glen Allen, VA 23060 ;
, Inspection Conducted:. September 16 through October 20, 1990 1nspectors: fflbh]/ Vw t/kp/ho M.Si Les'stpff enior Resident Inspector 5 Date Signed kb$ $/ Afderft Inspector n'//WS Date Signed ~
L . P . J. n e Approved by: e m /
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HIl0 $ O P.E. Fredrickson, 5~ection Chief Date Signed Division of Reactor Projects
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SUMMARY-Scope:
This routine inspection by the resident inspectors involved the following-areas: operations, maintenance, surveillances, modifications, operational event followup. licensee event report followup, midloop operations, and action on previous inspaction findings. Inspections of licensee backshift activities '
were conducted M the following days: September 19, 20, 21, 25, 26, and 2 Results:
One noncited violation was identified which involved the failure to revise procedures following an instrument air system design change, which had the potential for overloading the-EDG (paragraph 6.b).
The current Unit 2 refueling outage has been effectively managed to date by the licensee. One initiative that appears useful is:a method for identifying and tracking, until resolution, potentially significant safety or regulatory issues that occur during the outage. (paragraph 2)
The licensee has identified a potentially generic issue involving an additional heat of SG tube plugs which may be susceptible to PWSC (paragraph 2)
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l The inspectors identified a weakness in the licensee's equipment tagging program specific to master tagouts. Conditions requiring tagout boundary modification have led to two minor spills, personnel errors, resulting from procedural inconsistencies and lack of guidance, are the primary cause although outage planning methods need some improvement to minimize the challenge (paragraph 3.a)
Instances of missing abnormal procedures in the control room were identifie Copies were depleted by NRC operator license candidates during an examinatio Ato lack be theofcaus sensitivity regarding)
(paragraph maintenance of an inventory of copies appeared The inspectors reviewed the licensee's program for midloop operations which appeared adequate. One concern was identified involving the licensee's vent path through the hot leg. The licensee agreed to amplify their response to Generic Letter 88-17. The licensee's self assessment of the program was also reviewedandwasconsideredastrength.(paragraph 3.c)
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Preventive maintenance procedures for the new instrument air compressors have l not been completely updated as indicated by the reference to an incorrect grease for lubricating motor bearings. (paragraph 4.a)
l The inspectors reviewed the preventive and corrective maintenance program of the control room chillers in response to several recent chiller trips. While the program appeared adequate, some gages were noted not to be in the calibration program and sufficient data to adequately monitor chiller operating performance was not routinely recorded and evaluated by operator (paragraph 4.b)
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A weakness was identified with the licensee's program to revise and upgrade
! instrumentation procedure personnel identified many examples where additional changes were necessary for newly retyped procedures. Contrasting expectations of the goals of the program by various involved groups appeared to exis (paragraph 5.a)
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REPORT DETAILS 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. Heacock, Superintendent, Engineering
- G. Kane, Station Manager
- P. Kemp, Supervisor, Licensing
- Matthews, Superintendent Maintenance D. Roberts, Supervisor, Nuclear Safety Engineering R. Shears, Superintendent, Outage Management
- J. Smith, Manager, Quality Assurance
- A. Stafford, Superintendent Health Physics
- J. Stall, Superintendent. Operations Other licensee employees contacted included engineers, technicians, operators, mechanics, security force members, and office personne NRC Hesident inspectors L L. King, Resident inspector
- Lesser, Senior Resident Inspector
- Attended exit interview Acronyms and initialisms used throughout this repor: are listed in the last paragrap ,
! Plant Status Unit 1 started the period operating at 100 percent powe On September 24, RCS boron concentration reached 0 PPM and power coastdown was i initiated. The unit ended the reporting period at 82 percent power on day 269 of continuous operation.
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Unit 2 started the period in mode 6, completed refueling and ended the period in mode 5 at day 60 of the scheduled 75 day outage.
l The inspectors monitored progress of the Unit 2 refueling outage. The l licensee has used an effective method to identify to management poten-tially significant safety or regulatory issues which occur during the l outage. Each issue is trended and tracked until resolved. This appears to be helpful in assisting the licensee to manage the outage. Items inspected were replacement of the recirculation piping on the auxiliary feedwater
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pumps, inspection of the internals of the motor driven feed pump, maintenance on the main steam isolation valves and installation of new feedwater heater Tours were made of the containment during the l inspecten perio The 10 year ISI inspection was conducted along with a containmect Type A test. The outage has progressed well with only minor problem Steam generator tube inspections identif ed numerous cases of boron caked or wetted plugs as discussed in Inspet. ion Report 338,339/90-23. The plugs included a variety of heats susceptible to PWSCC as described in NRC Bulletin 89-01, Failure of Westinghouse Steam Generator Tube Mechanical Plugs and a new heat (NX-6323) which had been used to replace
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the susceptible heats during the February 1989, refueling outage. The l licensee performed ECT on a sample of plugs and detected indications on
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severa As a result of the findings, the licensee is replacing all hot l
leg Westinghouse Alloy 600 mechanical plugs with Alloy 690 plugs.
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Westinghouse has made proper notifications to the NR The licensee also identified a significant axially oriented indication
. measuring 0.6 inches, located approximately 5 inches above the third support plate on the hot leg side. This indication appears to be the major contributor to excessive primary to secondary leakage which forced the unit to shutdown early as discussed in Inspection Report 338,339/90-2 SG A and C were placed in category C-3 per TS 4.4.5.0 which means greater than one preent of the inspected tubes required plugging. The licensee will subm1t the required reports to the NR . Operational Safety Verification (71707)
The inspectors conducted frequent visits to the control room to verify proper staffing, operator attentiveness and adherence to approved procedure The inspectors attended plant status meetings and reviewed operator logs on a daily basis to verify operational safety, compliance with TS, and to maintain awareness of the overall operation of the facilit Instrumentation and ECCS lineups were periodically reviewed from control i room indications to assess operability. Frequent plant tours wert
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conducted to observe equipment status, fire protection programs, radiological work practices, plant security programs and housekeepin 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, Equipment Configuration Control Mishaps On September 29 with Unit 2 defueled, operations was filling portions of the charging pump suction lines when it was reported that water i
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was coming from the C charging pump cubicle roo It was determined that water had been _ suing from an open pump drain valve and two inches had accumulated on the floor. The pump suction valve was assumed to have been closed as part of a block tagout, however, its tag had been lifted and the valve was ope On September 30, approximately 350 gallons of water was lost from the VCT during an attempt to establish the boration flowpath required for fuel loading. It was discovered that tags establishing boundaries had been lifted and one drain valve was o n (2-CH-121) and another on the seal water return line was removed 2-CH-MOV-2381).
Although the unit was defueled during the e nts, the inspectors were concerned with the adequacy of controls fer wgging out system During the outage many systems are tagged using maste' tagouts which allow for multiple work activities within the boundary of the tagou When a boundary valve needs to be worked or tested, the master tagout boundary must be modified. VPAP-1402, Control of Equi and Tags, allows for a partial clearance (lifted tags)pment to accomplish Tagouts
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Some weaknesses were identifie New tags hung to modify the boundary were not linked to the new work activity, therefore, verification that the work activity is completed was not a requirement prior to clearing the new tag Memorandums issued to correct this problem have been ineffectiv The large volume of changes to the master tagout due to the testing or maintenance problems leads to personnel errors when clearing tag Inconsistencies in the methods for lifting tags exist in that some shift supervisors will fill out a partial clearance' form and others will prepare a new tagout shee Administrative procedures do not provide guidance. This leads to different methods of tracking lifted tag The licensee has im lemented a new log specif!cally for tracking lifted tags and i lemented time constraint requiroents for I rehanging them. Whi e it appears that the log will assist in maintaining control, better planning methods are needed to minimize the need to juggle master tagout boundaries. This weakness-regarding tagout control of equipment will continue to be reviewed as part of the core inspection progra Missing Procedures in the Control Room On September 25, a candidate being examined by the NRC for an operator license attempted to obtain a copy of 1-AP-10.1, Loss of
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Electrical Power, from the control room and found that the procedure was missing. The licensee later determined that 1-AP-3, Loss of Vital Instrumentation was also not in the control room. The ifcensee typically maintains an inventory of several copies of each AP in the control room. It was suspected that the copies had been depleted by license candidates during the walk-through portions of the NRC exam Discussions with NRC examiners indicated that on at least two occasions, the shift operators were made aware of depleting inventories on some procedure On September 26, the inspectors identified that 1-AP-1,1, Continuous Rod Insertion, was missin At this point, the licensee took action to correct the problem including replenishing all AP's and making appropriate persons aware of the concer The licensee believes the procedures were depleted due to excessive usage by the NRC license candidates. It is, however, unacceptable for personnel to remove the last copy of an AP from the control room as it would not be available for use during an event. The licensee initially did not recognize the extent of the problem until the inspectors found an additional AP missin Subsequent corrective actions were adequat Midloop Operations in preparation for scheduled midloop operations, the inspectors reviewed Generic Letter 88-17 " Loss of Decay Heat Removal" and the licensee's responses in addition to various draindown operating procedures and loss of RHR procedures. A concern was raised with the adequacy of the intended vent path on the hot leg with the loop stop valves shut. The path is through the surge line to the pressurizer and out the opening where the safety valves have been removed. The licensee's response to the Generic Letter did not specifically state that the surge line is connected to the hot leg at 90 degrees and the opening is submerged while drained down and does not uncover until
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the level is approximately six inches above centerlin The concern is that inventory could be lost out a cold leg opening due to pressurization until the surge line opening is uncovered. The licensee stated that Westinghouse has analyzed this concern and detennined that loss out the cold leg will result in a minor decrease of RCS inventory which will not affect the core. This was not discussedinthelicensee'sresponsetoexpeditiousaction(8)inthe Generic letter. The inspectors requested the licensee to updcte their response to addrest this issue. The licensee is preparing a followup response to the Generic Letter to address this concer The inspectors review of the li,ted items in the Generic letter indicated licensee compliance. The licensee corrected two items that were identified by operators during the training. One concern was
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that the RCS draindown procedures, as implemented, would not have correctly enabled the new RCS level indication and alarm. The second '
concern involved incorrect guidance on which emergency action level to declare f' ~: A ,g a loss of RHR for 15 minutes. The outage schedule i eventual 13 wppd and RCS inventory was not reduced to midloo Corporate Nuclear Safety conducted an assessment of the licensee's program for coping with a loss of decay heat removal capability. The assessment included a detailed review of procedures, controls, I testing, maintenance, training and use of operating experienc Strengths identified included effective prejob briefs, RCS mass balance calculation and good operator and staff sensitivit Concerns included a lack of procedural guidance for loss of I
electrical power or instrument air as a precursor for loss of decay
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heat removal, no specific procedural guidance to quickly restore electrical power using alternate methods, no routine performance testing of RHR heat exchanges, and no procedure available to. install the equipment hatch during containment closure. The inspectors reviewed the report and considered the initiative noteworthy and the assessment comprehensive. The licensee is iddressing the concerns :
raised by the assessrent team, Operator 12 Hour Shifts The licensed operator work shift was recently changed from 8 hours9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br /> to
! 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br />. The new 12 hour1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> shift is from 7:00 to 7:00 Five shifts will rotate through a ten wee', cycle which includes dwo weeks (8 l
days)oftraining. During the cycle, a shift will be scheduled for i either three or four consecutive work days followed by three to six days off. Operators generally are enthusiastic about the new schedule as it lends to a lower number of shift turnovers per day (two versus three)andindividualswillgetmoredaysof No violations or deviations were identifie . MaintenanceObservation(62703)
Station maintenance activities were observed / reviewed to ascertain that the cetivities were conducted in accordance with approved procedures, regulatory guides and industry codes or standards, and in conformance with TS requirements, Instrument Air Compressor Preventive Maintenance.
l On October 18, 1990, the inspector observed electrical maintenance l technicians attempt to perform the lubrication of instrument air l compresser 2-IA-C The preventive maintenance procedure was a generic procedure for electrical maintenance E-20-L6/C-4,
"PM - Electrical Maintenance." A review by the inspector of the
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technical manual for the compressor indicated that a General Electric !
bulletin for the motor was enclosed which covered a variety of motors !
and was not specific to the compressor motor. The manual indicated that the type of grease to be used was not that stated on the work orde They correctly questioned the type of grease to be used and obtained i the appropriate grease. This, however, indicated a planning weakness 1 in that the incorrect grease was referenced in the work order. The instrument air compressors are new compressors and the work order was based on the type of grease used in the compressors that had been replace The inspector requested licensee management to ensure themselves that the preventive maintenance procedures incorporate requirements from the new vendor manuals for the entire l c
(nstrument air system. Pending completion of licensee review, this
' is identified as inspector Followup Item 338/90-25-01: PM Program for
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IA Compressor Control Room Chillers The inspectors noted that there have been numerous instances of the l control room chillers tripping automatically for various reasons.
t The maintenance history of the chillers was reviewed for the last two years and indicated many instances of corrective maintenance. Several of the chiller trips were due to high discharge pressur The frequency of preventive maintenance was also reviewed and appeared adequate for routine preventive maintenance. The inspector reviewed the present logs to determine what operating parameters are monitored and determined that the logs do not monitor critical parameters. It was also determined that the gages are not calibrated on a periodic frequency and that some gages on the chiller appeared to be reading abnormal. The inspectors attempted to check out the technical manual for the chillers and could not find it in document control or in-the maintenance library. The licensee was notified of this proble *
The inspectors contacted the Assistant Station Manager for Operations and Maintenance concerning the log data taken who, in turn, requested engineering to investigate what parameters should be monitored. The Inspectors contacted enqineering and found that performance tests will be run on the chtl' ers with the aid of a consultant. The. tests '
will determine if the chillers are operating at capacit '
The present TS recuires that two chillers per unit be maintained -
operable to maintann a specific control room temperature. There are presently three chillers per unit which reduces the safety signifie '
! cance of the loss of one chille However, improved monitoring l
methods would preclude chiller trips. Pending development of an
! improved monitoring program by the licensee, this is identified as Inspector Followup Item 338/90-25-02: Improved Monitoring of Control Room Chillers.
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No violations or deviations were identified.
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7 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 deficiencies identified were properly reviewed and resolve Instrumentation Surveillance Procedures
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The inspectors reviewed portions of the licensee's procedure writing program for instrumentation procedures. The procedure writing groto currently is pursuing several different efforts in parallel including: Technical Revision Maintenance (TRM) to retype instrumentation procedures which currently have numerous pen and ink change . The addition of coincidence requirements (expected alarms or actuations during testing) to procedures in order to alert operators of an anticipated alarm or actuation. This effort is to meet an NRC commitment in response to previous problem . Procedure upgrade program to reformat procedures to a higher standar The inspectors became aware of several problems which have been hindering progress in this are Numerous procedures issued to meet the NRC commitment for adding coincidence recuirements for Unit 2 needed to be changed with a PAR because intenced sign off steps were not in the correct location. PARS were required to correct other administrative errors as well. It appeared that the stocedure writing group had not allocated enough time to conduct an acequate review to meet the comitment. The licensee is currently workin *
coincidence requirements and has allocated more time. g on the Unit 1 The procedure upgrade program is initially t6rgeting pts. Technical inaccuracies, identified during the verification and validation phase, appear to be due to incomplete understanding of the systems by the writers and lack of guidance on how to phrase actions and precautions in the procedures. It appears that more effective coordination is needed between procedure writers and I&C; however, the refueling outage demand on !&C resources is inhibiting this effor Back-to-back scheduled outages will not free up the necessary resources until March,1991. The procedures group has also had difficulty prioritizing work and allocating resources to adequately support the station's ongoing needs for design change
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packages, engineering work requests, and various commitment This
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1as resulted in the inability to maintain established goals for ( revised procedures. Expectations of management differ from 18 While 180 would like resources to concentrate on TRM, management is ;
opting for procedure upgrad ;
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1 The number of 1&C procedures routinely requiring changes is hig j The number of I AC procedures which required PARS during Sestember, ;
1990, was 153. The group with the ned highest number of PARS was i Operations with 81. The aggregate result of Qese problems appears )
to be frustration on the part of the procedure users,14C '
technician An incorrect IAC procedure contributed to an event in April,1990, there the RWST level channels were calibrated nonconservatively rendering the safety function inoperable. While no other significant 1 events have occurred to date due to inadequate procedures, weaknesses )
in the procedure writing program present this potential. Through i I
performance of routine duties, the inspectors will continue to monitor progress, On October 18, 1990, the inspector observed the following !
surveillances: PT-71.3"AuxiliaryFeedPumpTest(1-FW-P-38).
2, 2-PT-82.9H "2H Emergency Diesel Generator Test (Local
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No violations or deviations were identifie . Installation and Testing of Modifications (37828) RCS Level Indication L The ins >ectors reviewed Design Change 88-11-1 "RCS Draindown Level Indicat'on". This package installs a permanent sight glass in the containment and a level transmitter which reads M in the control room. The control room indication is enabled by 9 erating procedures
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l 1- and 2-0P-5.4 "Draint d the Reactor Coolant Syst)em."
The installation in the control room and the containment was reviewed l by the inspectors. The design change package and test procedures including the hydro tests were also reviewed. The inspectors reviewed the e. >ctrical load list, drawings, operating and alam >
response procedure and setpoint documents. All documents had been upgraded to include the new design and appeared adequate. No problems were identified with the design chang Potential EDG Overloading Due to IA Compressor Modification The licensee identified a concern regarding potential overload of the '
H EDG during a postulated design basis accident due to the addition of the new 1A compressors, added as a result of Design Change 89-0 The electrical system analysis of the design change considered the effects on the EDG of removing the old IA compressors and replacinq them with the new IA compressors. The conclusion was that the new A
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compressors would demand an idditional 12 HP from the H EDG. To alleviate the overloading potential, it was intended to ensure the containment air compressors would not start following a design basis accident. This would remove 15 to 20 H The containment air compressors are normally not running (IA supplies containment loads); however, they are maintained in automatic standby if header pressure dro)s. This would occur during a design basis accident because the IA 1eader would isolate. Since there are no automatic or administrative barriers to prevent the containment air _ compressors from starting, the design package required station operating procedures to be revised to ensure the containment air compressors are not starte Durinq a design- review following completio3 of the lA system insta'14 tion it was discovered t1st no admir,istrative measures to prevent starting the containment compressors had been taken. The licensee imediately issued Standing Order 176 to the operating shift to ensure the containment air compressors do not start following a design basis acciden Electrical engineering reviewed the ;
consecuence of the event and detemined that the EDG would have j exceeced to 2000 hours0.0231 days <br />0.556 hours <br />0.00331 weeks <br />7.61e-4 months <br /> rating of 3000 KW to a value to 3015 KW. The
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loading would have existed for up to two hours but is within the two hour short term rating of 3150 KW. The evaluation concluded the ED6 l would have been capab e of perfoming its intended safety function.
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The inspectors were concerned that the failure to implement the administrative controls was indicative of a design control proble The licensee's Administrative Procedure 5.28, Procedure Revisions Due to Design Changes, requires each department to review design packages to determine the procedures which will recuire revision. Although the design package stated " Station Operat< ng Procedures should be revised to take this limitation (no barrier to prevent containment
. air compressor start) into account,".the operations department failed ;
to identify the needed change. The effectiveness of periodic meet-
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I l ings between appropriate groups during the design package generation
! phase also appeared to be weak in this case in that the procedure L
revision requirement was not clearly comunicated by engineering to l operation This licensee identified violation is not being cited because the enforcement criteria specified in Section V.G.1 of the l
NRC Enforcement Policy were satisfied. NCV 338/90-05-03: Failure to Implement Procedure Revisions for Instrument Ali Cesign Chang One noncited violation was identifie . LERFollowup(92700)
The following LERs were reviewed and closed. The' inspector verified that reporting requirements had been met, that causes had been identified, that corrective actions appeared appropriate and that generic applicability had been considere Additionally, the inspectors confirmed that
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unreviewed sifety questions were involved and that violations of regulations oi 15 conditions had been identifie (Closed) LER 339/89-02: Entering LCO 3.0.3 During Hydrostatic Testing of the LHSI Lines. The licensee entered LCO 3.0.3 due to isolation of both trains of LHS! while in mode 3 in order to perfom 10 year hydrostatic testing of portions of the reactor coolant system. The event was preplanned and approved with the knowledge that it would be reportable and I
had appropriate administrative controls to ensure availability if neede The duration of the event was 41 minute . Followup of Operational Events (93702)
On September 24, 1990, at 0708, the licensee declared a NOVE due to the process vent gaseous radiation monitor (RM-Gk-102) reading nffscale high, greater than 1 E6 cpm. The licensee w5s performing maintenance on a leakinq outlet valve (1-CH-29) for the Unit 1 mixed bed domineralizer (1 CH .-1A). Following repairs to the valve, the domineralizer was vented to the process vent system and an attempt to fill with primary grade water was initiated. Operators initially noticed no flow rate when the fill path was opened, however, at this point, RM-GW-102 alarmed and the indication went off scale high. The alarm cleared and the radiation monitor came back on scale approximately one minute late Operators observed the trace from a redundant Kaman radiation monitor to peak at 1 E-2 microcuries per cubic centimeter and decay away over the next several minutes. The event was terminated at 073 The licensee determined the release to be approximately 0.6% of the Technical Specificat4n release limits. Generically, this is not the threshold for declaring an NOVE, however, EPIP 1.01 Emergency Action Level Table, Radioactivity Event, requires an NOUE if RM-GW-102 reads greater than 1 E6 cpm. This ap>arently is a conservative requirement due to the instrument being offscale at greater than 1 E6. The reference the Kaman monitor, which has a larger scale. procedure did not The license is reviewing their Emergency Action Level Table to more appropriately use the Kaman monitor to determine if an NOVE is require The licensee suspects the reason for the unplanned release was that t primary grade water header was pressurized due to valve leakby and caused excessive flow to the demineralize . Action on Previous Inspection Items (92701, 92702)
(Closed) Inspector Followup item 338, 339/89-30-05: Development of Abnormal Procedures and an Engineering Review of Breaker Size Relating to 120V AC Vital Bus Power Supplies. On October 17, 1989, Unit 1 experienced a loss of 120V AC vital bus power to a primary process rack when a feeder breaker opened. The licensee determined the primary power supply input i
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transformer had shorte The primary and backup power supplies are in
! parallel and each protected by a 30A fuse and 35A circuit breaker. A single 30A feeder breaker supplies the two power supplies. When the primary power supply shorted, the protective device coordination was such that the single 30A feeder breaker tripped instead of the faulted power supply fuse or breaker, thus losing both the ,rimary and backup per supplies. Operator action to prevent a reactor trip was required when power was lost to the feedwater regulating valves.
l The licensee revised annunciator response procedures to instruct operators
to refer to a load list and to notify the instrument shop of the failur The licensee also conducted s design study (NP 2323) which revealed inadequate protective device coordination and recommended separate feeder circuits for each backup power supply in the primary and secondary process racks and a preentive maintenance program which would replace either the powcr suppiy or selected components to help prevent inadvertent failures in the future.
. System engineering determined that a modification is not warranted based l on event frequency and relative payback. System engineering also stated I that the annunciator response procedure would ensure the primary power supply would be isolated by 14C upon notifiestion from operations. The inspectors believe, however, that a fault could still deenergize both the
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primary and backup power supplie The consequences of this would be a j i loss of one of four channels of protection and a potential reactor trip.
l While the plant is designed for such a transient, the inspectors concluded !
I that corrective action in this case was minimally acceptabl (Closed) Inspector followup Item 338/90-15-02: Policy Development for Testing Lineups Rendering Equipment inoperabl The licensee developed guidance for ensuring that applicable TS action statements are entered when equipment is rendered inoperable due to surveillance test lineu)s.
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- Instructions to the Shift Supervisor were provided in Operations Stancard
l System Status During Periodic Testin (Closed) Violation 338/89-28-03: Failure to Comply With Action Statement Requirements of TS 3.6.2.2 by Rendering Two Containment Spray Systems Operabl The licensee performed a HPiS evaluation of the event and i
determined that it was caused by poor comaunication and personnel error j concerning the current implementation of the tagou The event was discussed during training of the RO/SRO class and the lessons learned was incorporated into the SRO supervisory skills trainin (Closed) Violation 338,339/89-08-02: Violation of TS 4.6.1.1.A.1 for Containment Vent and Drain Isolation Valve The licensee reviewed 1- and 2-PT-60.1, Containment Integrity, and 1- and 2-PT-1E, Containment Checklist to incorporate permanent changes which verify that containment LMC's are closed and cappe (Closed) P2188-10: ASCO NP8314 Series Solenoid Valves Assembled with P80 L Lubricant May Stick in Energized Position Due to Solidification of P80.
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The notification by ASCO identified two of the suspect solenoid valves sold to the licensee. The licensee determined the two valves were purchased under Purchase Order NS30449, line item 001, stock item ,.
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07604500, however, the valves were never issued and were subsequently obsolete. The valves are no longer held in stoc I 10. Exit (30703) i The inspection scope and findings were sumarized on October 22, 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 inspectio Dissenting coments were not received from the license Item Number, Description and Reference IFl 338/90-25-01 PMProgramForIACompressors(paragraph 4.a)
IFl 338/90-25-02 Improved Monitoring of Control Room Chillers (paragraph 4.b)
NCY 338/90-25-03 Failure to implement Procedure Revisions for InstrumentAirDesignChange(paragraph 6.b)
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1 Acronyms and Initialisms AC - ALTERNATING CURRENT AP - ABNORMAL PROCEDURE CFR - CODE OF FEDERAL REGULATIONS CPM - COUNTS PER MINUTE ECT - EDDY CURRENT TESTING EDG - EMERGENCY DIESEL GENERATOR EPIP - EMERGENCY PLAN IMPLEMENTATION PROCEDURES HP - HORSEPOWER HPES - HUKAN PERFORMANCE EVALVATION SYSTEM IA - INSTRUMENT AIR I&C - INSTRUMENTATION AND CALIBRATION IFI - INSPECTOR FOLLOWUP ITEM 151 - INSERVICE INSPECTION KW - KILOWATTS LCO - LIMITING CONDITIONS FOR OPERATION LER - LICENSEE EVENT REPORT LHS! - LOW HEAD SAFETY INJECTION LMC - LOCAL MONITORING CONNEii10N NCY - NONCITED VIOLATION NOVE - NOTICE OF UNUSUAL EVENT NRC - NUCLEAR REGULATORY COMMISSION PAR - PROCEDURE ACTION REQUEST PPM - PARTS PER MILLION PT - PERIODIC TEST PWSCC- PRIMARY WATER STRESS CORROSION CRACKING RCS - REACTOR COOLANT SYSTEM
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RHR - RESIDUAL HEAT REMOVAL RO - REACTOR OPERATOR RWST - REFUELING WATER STORAGE TANK SG - STEAM GENERATOR SRO - SEN!0R REACTOR OPERATOR t TRM - TECHNICAL REVISION MAINTENANCE
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TS - TECHNICAL SPECIFICATION
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VCT - VOLUME CONTROL TANK i
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